Offshore Electricity Infrastructure in Europe - European Wind Energy ...

OffshoreGrid: 

Offshore Electricity 

Infrastructure 

in Europe

Offshore Electricity 

Grid Infrastructure 

in Europe 

A Techno-Economic Assessment 

3E (coordinator), 

dena, EWEA, ForWind, IEO, 

NTUA, Senergy, SINTEF 

Final Report, October 2011

PRINcIPAl AUThORS: 

Jan De Decker, Paul Kreutzkamp (3E, coordinator) 

AUThORS: 

3E (coordinator): Jan De Decker, Paul Kreutzkamp, Pieter Joseph, Achim Woyte 

Senergy Econnect: Simon Cowdroy, Peter McGarley 

SINTEF: Leif Warland, Harald Svendsen 

dena: Jakob Völker, Carolin Funk, Hannes Peinl 

ForWind:Jens Tambke, Lüder von Bremen 

IEO: Katarzyna Michalowska 

NTUA: George Caralis 

MAIN REvIEWERS: 

3E (coordinator): Jan De Decker, Paul Kreutzkamp, Natalie Picot 

dena: Jakob Völker 

EWEA: Sharon Wokke, Christian Kjaer, Jacopo Moccia, Frans Van Hulle, Paul Wilczek, Justin Wilkes 

EdITING: 

EWEA: Sarah Azau, Zoë Casey, Tom Rowe 

AckNOWlEdGEMENTS: 

Wilfried Breuer (Siemens), Paul Carter (SLP Engineering), Manuela Conconi (EWEA), Frederik Deloof (Secretariat Benelux), 

Frédéric Dunon (Elia), Dana Dutianu (EC), Rafael E. Bonchang (Alstom Grid), Claire Grandadam (3E), Jan Hensmans (FOD 

Economie), Andrea Hercsuth (EC), Matthias Kirchner (Nexans), Niels Ladefoged (EC), Nico Nolte (BSH), Antje Orths (Energinet. 

dk), Glória Rodrigues (EWEA), Fabian Scharf (BNetzA), Christophe Schramm (EC), Alberto Schultze (Siemens), Ravi Srikandam 

(arepo consult), Guenter Stark (ABB), Gina Van Dijk (Tennet), Heleen Van Hoof (VREG), Jan van den Berg (Tennet), Teun Van 

Biert (Tennet), Karina Veum (ECN), Bo Westman (ABB) 

design: www.mardi.be; 

Print: www.artoos.be; 

Production coordination: Raffaella Bianchin, Cristina Rubio (EWEA); 

cover photo: Detlev Gehring/ Stiftung Offshore Windenergie 

Agreement n.: EIE/08/780/SI2.528573 

Duration: May 2009 – October 2011 

Co-ordinator: 3E 

The sole responsibility for the content of this publication lies with the authors. It does not necessarily 

reflect the opinion of the European Union. 

Neither the EACI nor the European Commission are responsible for any use that may be made of 

the information contained in this publication. 

2 OffshoreGrid – Final Report

COORDINATOR 

PROjeCT PARTNeRs: 

The Deutsche Energie-Agentur 

GmbH (dena) - the German 

Energy Agency - is the centre of 

expertise for energy efficiency, 

renewable energy sources and 

intelligent energy systems. 

www.dena.de 

IEO: Institute for Renewable 

Energy is a Polish independent 

consultancy company and a 

think tank, linking research, 

technology and policy 

development activities in the 

area of renewable energy. 

www.ieo.pl 

Supported by 

OffshoreGrid – Final Report 

3E is a global, independent 

renewable energy consultancy, 

providing full-scope technical 

and strategic guidance in wind 

(on & offshore), solar, grids and 

power markets. 

www.3e.eu 

The European Wind Energy 

Association (EWEA) is the 

voice of the wind industry, 

actively promoting the 

utilisation of wind power in 

Europe and worldwide. 

www.ewea.org 

NTUA-RENES: The Renewable 

Energy Sources unit is an 

educational and research unit in 

the National Technical University 

of Athens dedicated to the 

promotion of renewable energy 

sources. 

www.ntua.gr 

SINTEF Energy Research is a 

Norwegian research institute that 

develops solutions for electricity 

generation and transformation, 

distribution and end-use of energy, 

onshore and offshore/subsea. 

www.sintef.no 

ForWind, the joint centre for 

wind energy research of the 

universities of Oldenburg, 

Hannover and Bremen is one 

of Europe’s leading academic 

institutions for all aspects 

of wind energy, from turbine 

design to large-scale wind flow 

simulations. 

www.forwind.de 

Senergy Econnect specialise 

in the electrical connection 

of renewable energy projects 

to grid networks; from initial 

concept, to design and 

commissioning worldwide. 

www.senergyworld.com 

3

Table of contents 

FOREWORd 6 

EXEcUTIvE SUMMARY 7 

1 INTROdUcTION 17 

1.1 Context and background 18 

1.2 Objective of OffshoreGrid 19 

1.3 Methodology and approach 19 

1.4 Stakeholders 19 

1.5 Document structure 20 

2 kEY ASSUMPTIONS ANd ScENARIOS 21 

2.1 Offshore wind development scenarios in Northern Europe 22 

2.2 Generation capacity and commodity price scenarios 23 

2.3 Technology to connect offshore wind energy 25 

3 METhOdOlOGY - SIMUlATION INPUTS ANd MOdElS 27 

3.1 Wind power series model 28 

3.2 Power market and power flow model 29 

3.3 Infrastructure cost model 29 

3.4 Case-independent model 30 

4 RESUlTS 31 

4.1 Wind output statistics 32 

4.1.1 Spatial smoothing of wind power 32 

4.1.2 Spatial power correlations 33 

4.2 Wind farm hubs versus individual connections 35 

4.2.1 Hubs and individual connections in the sea basins in Northern Europe 36 

4.2.2 Overall cost reductions expected from shared connections via hubs 39 

4.2.3 Scheduled wind farm connection – risk of stranded hub investments 40 

4.2.4 Conclusion and Discussion on Hubs versus Individual Connections 42 

4.3 Integrated design – case studies 42 

4.3.1 Tee-in solutions – Case study evaluation 43 

4.3.2 Hub-to-hub solutions – Case study evaluation 46 

4.4 Integrated design – case-independent model 49 

4.4.1 Minimum distance for tee-in solution 49 

4.4.2 Maximum distance between hubs for integrated hub solution 52 

4.4.3 The Cobra cable case study 55 

4.4.4 Conclusion on integrated design 57 

4.5 Overall grid design 58 

4.5.1 Approach 58 

4.5.2 The Direct Design methodology 59 

4.5.3 The Split Design methodology 64 

4.5.4 Comparison of methodologies 69 

4.5.5 Infrastructure investment – circuit length and total costs 74 

4.5.6 Power system impact of the offshore grid 77 

4.5.7 Conclusion and discussion 78 


5 TOWARdS AN OFFShORE GRId – FURThER cONSIdERATIONS 81 

5.1 Challenges and barriers 82 

5.1.1 Operation and maintenance of an offshore grid and further technical challenges 82 

5.1.2 Regulatory framework and policy 84 

5.1.3 Market challenges and financing 86 

5.1.4 Supply chain 86 

5.2 Ongoing policy and industry initiatives 87 

6 cONclUSIONS ANd REcOMMENdATIONS 89 

6.1 Wind farm hubs 90 

6.2 Tee-in solutions 91 

6.3 Hub-to-hub solutions 92 

6.4 Overall grid design 94 

6.5 Overall recommendations 96 

7 AckNOWlEdGEMENTS ANd FUNdING 99 

8 REFERENcES 101 


5

FOREWORD 

The OffshoreGrid project is the first in-depth analysis of how to build a cost-efficient 

grid in the North and Baltic Seas. As such, it is a compelling milestone in the 

development of a secure, interconnected European power system, able to integrate 

increasing amounts of renewable energy. 

The need for cleaner and safer energy supplies to counter climate change is clear. 

Renewable power is key to achieving Europe’s 20-20-20 targets and to cope with energy 

related challenges far beyond 2020. Offshore wind, in particular, has tremendous 

potential. It could generate more than 500 TWh per year by 2030, enough electricity 

to meet 15% of Europe’s yearly electricity consumption. 

However, reaching these goals and moving towards an efficient, integrated European electricity market will not 

be possible without a reliable, modernised and efficient grid, both onshore and offshore. Onshore, this means 

significant investments to strengthen current infrastructure, which faces strong public opposition and lengthy 

project lead times. Offshore, the challenge is to more efficiently connect power harvested at sea with the 

onshore transmission system, while at the same time building a system which can actively contribute to stability 

and security of supply by enabling further integration of the European power market. A coherent European 

long-term vision for both the onshore and offshore electricity grid is a prerequisite to make the required steps in 

an optimal way. 

The OffshoreGrid project results are a practical blueprint for policymakers, developers and transmission grid 

operators, to plan and design a meshed offshore grid. They provide explicit guidance for individual projects while 

not losing sight of the overall grid design. The analysis of costs and benefits of different configurations addressed 

in this study will help policy makers and regulators anticipate developments and provide incentives that trigger 

the necessary investments at the right time and avoid stranded investments. 

Taking the OffshoreGrid results as basis for discussion, a concrete roadmap for a grid at sea can be developed 

involving all stakeholders. With today’s fast developments in the offshore wind industry, now is our opportunity. 

Geert Palmers, 

CEO, 3E 


ExEcuTivE SuMMAry 

• The OffshoreGrid project 

• Main results in a nutshell 

• Analysis of different connection concepts 

• General recommendations 

Photo: Vestas

Executive Summary 

I. The OffshoreGrid project 

OffshoreGrid is a techno-economic study funded by the 

EU’s Intelligent Energy Europe (IEE) programme. It has 

developed a scientific view on an offshore grid in northern 

Europe along with a suitable regulatory framework 

that takes technical, economic, policy and regulatory 

aspects into account. This document is the final report 

of the project. It summarises the key assumptions, 

the methodology and the results, draws conclusions 

from the work and provides recommendations. 

The benefits of an offshore grid 

The exploitation of Europe’s offshore wind potential 

brings new challenges and opportunities for power 

transmission in Europe. Offshore wind capacity 

in Europe is expected to reach 150 GW in 2030 1 . 

The majority of the sites currently being considered 

for offshore wind projects are situated close to the 

European coast, not further than 100 km from shore. 

This is in part due to the high cost of grid connection, 

limited grid availability and the absence of a proper 

regulatory framework for wind farms that could feed 

several countries at once. Looking at the North Sea 

alone, with its potential for several hundreds of 

Gigawatts of wind power, an offshore grid connecting 

different Member States would enable this wind 

power to be transported to the load centres and at 

the same time facilitate competition and electricity 

trade between countries. A draft working plan for 

an inter-governmental initiative known as the North 

Seas Countries’ Offshore Grid Initiative (NSCOGI) 

summarises the advantages of such a grid 2 : 

• Security of supply 

– Improve the connection between big load centres 

around the North Sea. 

– Reduce dependency on gas and oil from unstable 

regions. 

– Transmit indigenous offshore renewable electricity 

to where it can be used onshore. 

– Bypass onshore electricity transmission 

bottlenecks. 

• competition and market 

– Development of more interconnection between 

countries and power systems enhances trade 

and improves competition on the European energy 

market. 

– Increased possibilities for arbitrage and limitation 

of price spikes. 

• Integration of renewable energy 

– Facilitation of large scale offshore wind power 

plants and other marine technologies. 

– Enabling the spatial smoothing effects of wind 

and other renewable power, thus reducing variability 

and the resulting need for flexibility. 

– Connection to large hydropower capacity in 

Scandinavia, introducing flexibility into the power 

sys tem to compensate for variability from wind 

and other renewable energy sources. 

– Contribution to Europe’s 2020 targets for renewables 

and CO 2 emission reductions. 

II. Main results in a nutshell 

The OffshoreGrid study confirms these advantages 

after having investigated both the technical and economic 

questions. 

The first step was to study the connection of the offshore 

wind farms to shore, without looking into the 

details of an interconnected solution yet. In this regard 

OffshoreGrid comes to the conclusion that using 

hub connections for offshore wind farms – that is, 

connecting up wind farms that are close to one another, 

forming only one transmission line to shore - is 

often highly beneficial. OffshoreGrid assessed 321 

offshore wind farm projects, and recommends that 

114 of these 321 be clustered in hubs. If this were 

done, OffshoreGrid has calculated that €14 bn could 

be saved up to 2030 compared to connecting each 

of the 321 wind farms individually to shore – that is, 

investments would be €69 bn as opposed to €83 bn. 

1 EWEA, Pure Power – Wind energy targets for 2020 and 2030, 2011 update, July 2011. 

2 Draft Working Plan Proposal for Offshore Electricity Infrastructure, 3E for Belgian Ministry of Energy, Unpublished, 2010. 


Based on this connection scenario (called the “hub 

base case sce nario”) in a second step two highly costefficient 

interconnected grid designs were then drawn 

up - the “Direct Design” and “Split Design”. 

In the Direct Design, interconnectors are built to promote 

unconstrained trade between countries and 

electricity markets as average price difference levels 

are high. Once additional direct interconnectors become 

non-beneficial, tee-in, hub-to-hub and meshed 

grid concepts are added to arrive at an overall grid 

design (for an explanation of these terms, see Section 

III of the Executive Summary). 

The Split Design is essentially designing an offshore 

grid around the planned offshore wind farms. Thus, 

as a starting point not only direct interconnectors are 

investigated but also interconnections are built by 

splitting the con nection of some of the larger offshore 

wind farms between countries. These “split wind farm 

connections” establish a path for (constrained) trade. 

These offshore wind farm nodes are then - as in the 

Direct Design - further interconnected to establish an 

overall ‘meshed’ design where beneficial. 

The overall investment costs are €86 bn for the Direct 

Design and €84 bn for the Split Design. This includes 

€69 bn of investment costs for the most efficient connection 

(hub-connections where beneficial as in the 

FIGURE 1.1: TOTAl INvESTMENTS FOR ThE OvERAll GRId dESIGN 


cost (€bn) 

100 

Reference and base case 

90 

92 

80 

83 

78 

70 

60 

50 

40 

30 

20 

10 

69 

0 

Radial Base case Hub Base case 


Split offshore grid design 

Direct offshore grid design 

hub base case scenario) of the 126 GW of offshore 

wind farms to shore, as well as about €9 bn for interconnectors 

planned within the Ten Year Network 

Development Plan (TYNDP) of the European transmission 

system operator association (ENTSO-E). The rest 

of the investments that make up the €84 bn or €86 bn 

for this further interconnected grid are €7.4 bn for the 

Direct Design and €5.4 bn for the Split Design. These 

relatively small additional investments generate system 

benefits of €21 bn (Direct Design) and €16 bn 

(Split Design) over a lifetime of 25 years – benefits of 

about three times the investment. 

Both designs are thus highly beneficial, from a socioeconomic 

perspective. When comparing in relative 

terms by looking at the bene fit-to-CAPEX (Capital 

Expenditure) ratio, the Split Design is slightly more 

cost-effective than Direct Design and yield a higher 

benefit return on investment. 

The investments in offshore grid infrastructure have to 

be compared with the offshore wind energy produced 

over 25 years which amounts to 13,300 TWh. This 

represents a market value of €421 bn when assuming 

an average spot market price of €50/MWh. In this 

context, the infrastructure costs represent about a 

fifth of the value of the electricity that is generated 

offshore. The additional cost for creating the meshed 

offshore grid (even including wind farm connections 

Overall grid design 

System bene�ts due 

to reduced electricity 

generation costs 

over 25 years (€bn) 

100 

86 

84 

90 

80 

70 

60 

50 

40 

30 

€ 21 

€ 16 

20 

10 

Direct Design 

Split Design 

0 

ENTSO_E Interconnectors 

Hub and Tee-in connections 

Radial Connections 

Annual generation bene�ts 

9


and TYNDP interconnectors) would amount to only 

about €¢ 0.1 per KWh consumed in the EU27 over 

the project life time [57]. 3 

In addition to connecting 126 GW of offshore wind 

power to the grid, the offshore interconnection capacity 

in northern Europe is, as a result, boosted from 

8 GW today to more than 30 GW. 

There are many other benefits from the investments 

in an offshore grid, including connecting generation 

in Europe (in particular wind energy) to the large hydro 

power “storage” capacities in northern Europe, 

which can lower the need for balancing energy within 

the different European regions. Offshore hubs also 

mitigate the environmental and social impact of laying 

multiple cables through sensitive coastal areas and 

allow for more efficient logistics during installations. 

Furthermore a meshed offshore grid based on the teein 

concept and hub-to-hub interconnections makes the 

offshore wind farm connection more reliable and can 

significantly increase security of supply within Europe. 

The overall circuit length needed for both offshore 

grid designs is about 30,000 km (10,000 km of AC 

cables, 20,000 km of DC cables). The hub base case 

scenario accounts for 27,000 km, while the additional 

circuit length to build the Direct or the Split Design is 

only about 3,000 km. As AC circuits use 1 x 3 core AC 

cable and DC circuits use 2 x 1 core DC cables, the 

total cable length is even higher. 

Figure 1.1 on page 9 summarises the overall investments 

required of the different grid options. 

III. Analysis of different 

connection concepts 

There are different ways of building offshore grid 

infrastructure to interconnect power mar kets and offshore 

wind power. In this report, different innovative 

configurations for interconnection are assessed for 

feasibility, looking at factors such as technological 

availability, infrastructure costs, system operation 

costs, geographical situation, electricity production 

and trade patterns: 

• Wind farm hubs: the joint connection of various 

wind farms in close proximity to each other, thus 

forming only one transmission line to shore. 

• Tee-in connections: the connection of a wind farm 

or a wind farm hub to a pre-existing or planned 

transmission line or interconnector between countries, 

rather than directly to shore. 

• Hub-to-hub connection: the interconnection of 

several wind farm hubs, creating, thus, transmission 

corridors between various countries (i.e. the 

wind farm hubs belonging to different countries 

are connected to shore, but then also connected 

to each other). This can also be interpreted as an 

alternative to a direct interconnector between the 

countries in question. 

Based on all these design options as well as using 

conventional direct country-to-country interconnections, 

an overall grid design was developed (as already 

discussed in section II). A detailed techno-economic 

cost benefit analysis of the design was carried out in 

order to find how it could be made most cost-effective. 

Which connection concept is best depends on several 

factors, such as the distribution of the offshore 

wind farms (for example, whether there is more than 

one farm planned in the vicinity), the wind farms’ distance 

to shore, and in the case of interconnecting 

several wind farms and/or countries, the distance of 

the farms to each other and the electricity trade between 

the countries. Recommendations and general 

guidelines regarding the choice of the best connection 

concept are discussed below. 

It is important to point out that policy makers and 

regulators will require a significant amount of advance 

planning and insight in order to provide the correct 

incentives to simulate the development of meshed 

grid solutions. These incentives should be targeted 

towards creating favourable conditions for the necessary 

investments required, as well as ensuring they 

3 The additional cost for creating the meshed offshore grid (excluding wind farm connections and TYNDP interconnectors) would 

amount to only about €¢ 0.01 per KWh. 


occur in a timely manner so as to avoid stranded 

investments. The costs and benefits of such investments, 

the main parameters that influence them, and 

the technical and operational implications of technology 

choices need to be considered before investment 

decisions are taken. 

III a. Wind farm hubs 

Hub connections generally become economically viable 

for distances above 50 km from shore, when the sum 

of installed capacity in a small area (~20 km around 

the hub) is relatively large, and standard available 

HVDC Voltage Source Converter (VSC) systems can be 

used. Wind farms situated closer than 50 km to an onshore 

connection point are virtually always connected 

individually to shore. OffshoreGrid assessed more than 

321 offshore wind farm projects, and recommends that 

114 out of these be clustered in hubs. Apart from the 

costs savings, offshore hubs can also help to mitigate 

the environmental and social impact of laying multiple 

cables through sensitive coastal areas and allow for 

more efficient logistics during installations. 

One of the primary difficulties with this kind of interconnection 

is long-term planning. Offshore farms are 

not always built at the same time or at the same 

speed, requiring the hub connection to be sized anticipating 

the capacity of all the farms once completed. 

Therefore it might be necessary to oversize the hub 

temporarily until all the planned wind farms are built. 

This of course also bears the risk of stranded investment 

should some of the wind farms never get built. 

However, OffshoreGrid shows that the costs of temporarily 

oversizing and stranded investments are limited 

and that hub connections can still be beneficial even 

if wind farms are built across a life span of more than 

ten years. In certain cases the hub even remains beneficial 

if some of the wind farms connected to the hub 

are not built at all. 

III b. Tee-in connection and split wind 

farm connection 

Whether connecting offshore wind farms to interconnectors 

is beneficial depends primarily on the balance 

between the additional costs due to trade constraints 

on the interconnector and cost savings due to reduced 

infrastructure. The trade constraints occur when an 

offshore wind farm is connected to the interconnector 


as the availability of the interconnector for international 

electricity exchange is reduced. The costs savings 

occur as the overall infrastructure costs are generally 

lower: the cable length to connect the wind farm to the 

interconnector is usually much shorter than the cable 

required to connect the wind farm to shore. Tee-in solutions 

generally become more beneficial (compared 

to direct interconnections) when : 

• Electricity price differences between the connected 

countries are not too large, 

• The wind farm is far from shore and close to the 

interconnector, 

• The country where the wind farm is built has the 

lower electricity price of the two (the tee-in then 

gives the opportunity to sell to the country with the 

higher prices), 

• The wind farm capacity is low compared to the interconnector 

capacity (low constraints), 

• The wind farm capacity is roughly double the interconnector 

capacity. 

An interesting case that can be considered a variant of 

the tee-in concept is the split connection of large wind 

farm hubs far from shore. By connecting the wind farm 

hub to two countries instead of one, the wind farm is 

connected to shore and at the same time an interconnector 

is created with a modest additional investment. 

III c. Hub-to-hub interconnection 

Hub-to-hub connections are generally beneficial when 

the potentially connected countries are relatively far 

from each other, and the wind farm hubs are far from 

shore but close to each other. In this manner the 

costs saved due to reduced infrastructure generally 

outweigh the negative impact that can occur due to 

trade constraints imposed by transmission capacity 

reduction. This finding is similar to the conclusions in 

the tee-in scenario. 

In general the hub-to-hub connection is more beneficial 

than direct interconnectors under the same 

conditions that make the tee-in connection beneficial: 

modest price difference between interconnected countries, 

the capacity of the wind farm and its connection 

is high compared to the interconnector capacity (lowering 

trade constraints), and capacity towards the 

country with the highest price of electricity is higher 

than in the other direction. 

11


One of the keys to the successful implementation of 

a hub-to-hub connection is long-term planning. Often 

the wind farms that are to be included in the hub-tohub 

connection are not all developed at the same 

time. Advanced planning will thus be required to take 

into consideration issues such as the future capacity 

needs of the connection to shore once the other wind 

farms are completed (in order to provide extra capacity 

for international exchange). 

FIGURE 1.2: dIREcT OFFShORE GRId dESIGN 

Wind Farms Onshore substation 

To shore Connection of Wind Farms 

(Hub and Individual) 

Existing Interconnectors 

Entso-E TYNDP Interconnectors 

Kriegers Flak – Three Leg Interconnector 

2x Direct Interconnector 

close to each other 



Direct Design step 3 

Meshed Grid Design 

III d. Overall grid design 

The development of the offshore grid is going to be 

driven by the need to bring offshore wind energy online 

and by the benefits from trading electricity between 

countries. This involves on the one hand the connection 

of the wind energy to where it is most needed, and 

on the other hand the linking of high electricity price 

areas to low electricity price areas. The OffshoreGrid 

consortium has demonstrated the effectiveness of 

Direct Design step 1 – Direct Interconnectors 


Hub-to-hub and Tee-in interconnectors 



More detailed maps 

including information on 

the voltage level, 

the number of circuits 

and the technology 

(monopole or bipole DC) 

can be downloaded from 

www.offshoregrid.eu 


two different methodologies for the design of a costeffective 

overall offshore grid: 

• The direct design builds on high-capacity direct interconnections 

to profit from high price differences, 

then integrated solutions and meshed links are 

applied, 

FIGURE 1.3: SPlIT OFFShORE GRId dESIGN 










Split Design step 3 


• The Split design starts by building lower-cost interconnectors 

by splitting wind farm connections in 

order to connect them to two shores, then integrated 

solutions and meshed links are applied. 

Both designs were developed following an iterative approach 

based on the modelling of infrastructure costs 

and system benefits. The end-result of both designs is 

shown in Figures 1.2 and 1.3. 



2x Split wind farm connection 


Split Design step 1 – Direct Interconnectors 

Split Design step 1 – Split Wind farm connections 









13


Splitting wind farm connections to combine the offshore 

wind connection with trade as in the Split 

Design has proven to be slightly more cost-effective 

than building direct interconnec tors only for trade. 

The average reduction in CAPEX from choosing a split 

connection over a direct interconnector is more than 

65%, while the reduction in system cost is only about 

40% lower on average. A comparison of the benefit 

per invested Euro of CAPEX revealed that in the Split 

Design for each Euro spent about 3 Euros are earned 

as benefit over the lifetime of 25 years, while for the 

Direct Design these are only 2.8 Euros. Thus, the Split 

Design is slightly more cost-effective. However both 

Designs are highly efficient. 

In addition to its techno-economic advantages, the 

Split Design also has environmental benefits because 

it reduces the total circuit length. Moreover, it improves 

the redundancy of the wind farm connection, 

which improves system security and reduces the system 

operation risks, the need for reserve capacity, and 

the loss of income in case of faults. When doing detailed 

assessments for concrete cases, these merits 

should not be overlooked. 

However, in the end both designs produce large benefits 

and are advantageous from the power system’s 

perspective, but tee-in solutions, hub-to-hub solutions 

and split wind farm connections raise the issue of 

possible regulatory framework and support scheme 

incompatibilities between European countries. The 

reason is that renewable energy that is supported by 

one country can now flow directly into another country, 

so that the country paying for it cannot enjoy all 

the benefits. For split wind farm connections, this is 

even more difficult as the connection to the country in 

which the wind farm is located is reduced. As these 

complexities add risks to the development of integrated 

and especially split connections, they should be 

solved at bi-lateral, European and international level 

as soon as possible. 

An offshore grid will be built step by step. The two 

designs presented (Figures 1.2 and 1.3) show two possible 

configurations for such an offshore grid in 2030, 

both of which are largely beneficial. Every new generation 

unit, interconnection cable, political decision or 

economic parameter has an impact on both the future 

and the existing projects and thus can have a large 

influence on the development of the offshore grid. The 

two designs, and the different conclusions drawn on 

the way, bring useful insights that will allow the industry 

to know how to react to and guide the offshore grid 

development process over the next few years. 

III.E Additional benefits of hub 

connections and interconnected 

grid designs 

The investments required for an offshore grid and the 

economic viability of the chosen connection and interconnection 

concepts are of high importance. However 

at the same time other aspects, such as system 

security and the environmental impact of different grid 

designs have to be taken into account. 

It must be emphasised that connecting offshore wind 

farms in hubs not only reduces the investment costs 

in many cases but also reduces the number of cables, 

the maritime space use as well as the environmental 

impact due to shorter and more concentrated construction 

times. 

Integrated design configurations such as tee-in 

solutions, hub-to-hub connections or even further 

intermeshed designs have the benefit of increased 

n-1 security. This does not only increase the security 

of supply for the consumer and facilitate 

system operation, it also gives additional security to 

the wind farm operator as losses due to single cable 

failures are reduced. 

On the other hand, these integrated grid design 

configurations are also more complex in the planning 

and construction phase and may conflict with existing 

regulatory frameworks or potential incompatibilities 

of different national support schemes. Furthermore 

the safe multi-terminal operation of such an offshore 

grid based on HVDC VSC technology requires fast DC 

breakers, which are still in the development phase at 

the time of writing. 


IV. General recommendations 

To make the offshore grid more cost-effective and 

efficient, the innovative connection and interconnection 

concepts discussed above should be applied. 

The following selected key recommendations should 

be taken into account when considering the future of 

offshore wind development: 

• Where wind farm concession areas have already 

been defined, regulation should be designed to 

ensure that wind farm integration using one of 

the methods proposed above is favoured over 

traditional individual connections, wherever this is 

beneficial with regards to infrastructure costs. In 

particular the hub connection of wind farms is technically 

state of the art and can be beneficial, 

• In countries where there is currently no strategic 

siting or granting of concessions, policy makers 

should aim for fewer areas with a larger number of 

concentrated wind farms, with projects within one 

area to be developed all at the same time, rather 

than for more and smaller concession areas. In 

line with the expected development of technology, 

the optimal installed capacity in areas where a hub 

connection is possible should be around 1,000 MW 

for areas developed in the coming ten years, and 

2,000 MW for areas developed after 2020, 

• Integrated solutions such as tee-in and hub-to-hub 

solutions can be very beneficial compared to conventional 

solutions. For wind farms or hubs far from 

shore, a tee-in to a nearby interconnection (if available) 

or a split of the wind farm connection to two 

countries should be investigated. When developing 

international interconnection cables, the possibility 

of hub-to-hub solutions should be investigated, 

particularly when there are large wind farm hubs in 

each country far from shore but close to each other, 

• Any new interconnector will have an economic impact 

on the interconnectors already in place, as 

it will reduce the price differences between the 

countries. Integrated solutions are less dependent 

on trade than a direct interconnector, and can 

therefore still be beneficial even with lower price 

differences. Where possible, opportunities for 

splitting wind farm connections should be carefully 

checked and pursued. The case-independent 

model developed in this project can serve for quick 

pre-feasibility studies, 


• The ongoing development of direct interconnectors 

should not be slowed down, as this concept can 

already be built today independently of the development 

of large wind farms far from shore, which 

could be beneficially teed-in. However it is advisable 

to anticipate tee-in connections for suitable 

wind farms in the future, 

• The policy for merchant interconnectors which 

receive exemption from EU regulation should be 

reviewed. The concept of merchant interconnectors 

can incentivise investments that bear high risks. 

However, investors in, and owners of, merchant interconnectors 

could have an incentive to obstruct 

any new interconnector, as this would reduce their 

return on investment. It is therefore absolutely 

necessary that there are no conflicts of interest, 

for example between private investors with a key 

role in grid planning, grid operation or the political 

decision processes concerned with these issues. 

Otherwise the endeavour to have a single EU market 

for electricity is put at risk, 

• Tee-in connections, hub-to-hub connections and 

split wind farm connections have shown to be costefficient 

in many cases. Furthermore these grid 

designs can increase system security and reduce 

environmental impact. Policy makers and regulators 

should prepare measures to support such 

innovative solutions, which are not yet included in 

most current legal and political framworks. In particular, 

the compatibility of support schemes and 

the allocation of benefits should be adressed as 

soon as possible, bilaterally or internationally. The 

North Seas Countries’ Offshore Grid Initiative is a 

good framework within which to coordinate crossborder 

issues surrounding the political, regulatory 

and market aspects, 

• When considering cross-border connections, 

offshore grid development should be a joint or coordinated 

activity between the developers of the wind 

farms, their hub connections, and transmission 

system operators (TSOs). The North and Baltic Sea 

countries should adapt their regulatory frameworks 

to foster such a coordinated approach. 

15



INTRODuCTION 

• context and background 

• Objective of OffshoreGrid 

• Methodology & approach 

• Stakeholders 

• Further presentation and discussion of results 

• Document structure 

Photo: Photo: Dong Vestas Energy

introduction 

1.1 Context and background 

Europe has ambitious targets for renewable energy 

deployment. By 2020, 20% of gross final energy consumption 

should be met by renewable sources [19]. 

Offshore wind power is expected to deliver a large contribution. 

An installed capacity of 40 GW of offshore 

wind power is expected in Europe by 2020, in 2030 

this can amount to 150 GW, of which about 126 GW 

will be located in Northern Europe [20]. 

The EC 2050 Roadmap [21] fosters this development 

further with the long-term target to cost-efficiently reduce 

European Greenhouse Gas emissions by 80% 

to 95% by 2050. This goal is only achievable with 

large-scale deployment of renewable energy generation 

with offshore wind energy as a dominant 

generation source. 

Consequently, the number of wind farms is expected 

to increase rapidly within the next decade, particularly 

in the North and Baltic Seas. All these wind farms 

will have to be connected to onshore power systems. 

This raises questions on how to connect the future 

wind power capacity and how to integrate it into the 

national power systems in an efficient and secure way. 

The first offshore wind farms were connected individually 

to the onshore power system. However, these wind 

farms were limited in capacity and relatively close to 

shore. Future wind farms may be up to several thousand 

MW’s, at distances of more than 200 km from 

shore. In particular for these wind farms bundling the 

electric connection at sea and carrying the energy over 

a joint connector to the onshore connection points can 

be more efficient than individual connections of wind 

farms to shore. This so-called hub connection design 

can reduce costs, space usage and environmental impact 

dramatically. Once these wind farms or hubs are 

in place, new connection design opportunities open: 

The hubs can be teed-in to interconnectors, or can be 

interlinked with other hubs or to other shores, creating 

a truly integrated offshore power system. 

This thinking is particularly driven by the idea that 

such an offshore grid can bring a variety of benefits 

to the security of the power system, the European 

electricity market and the overall integration of renewable 

energy. 

• Increased security of supply: 

- improve the connection between big load centres 

around the North Sea, 

- reduce dependency on gas and oil from unstable 

regions, 

- transmit indigenous offshore renewable electricity 

to where it can be used onshore, 

- bypass onshore electricity transmission 

bottlenecks. 

• Further market integration and enhancement of 

competition: 

- more interconnection between countries and 

power systems enhances trade and improves 

competition on the European energy market, 

- increased possibilities for arbitrage and 

limitation of price spikes. 

• Efficient integration of renewable energy: 

- facilitation of large-scale offshore wind power 

plants and other marine technologies, 

- valorisation of the spatial smoothing effect of 

wind power and other renewable power, thus 

reducing variability and the resulting flexibility 

needs, 

- connection to the large hydropower capacity in 

Scandinavia, thus introducing flexibility in the 

power system for the compensation of variability 

from wind power and other renewable power, 

- significant contribution to European 2020 

targets. 

However, there is a long list of technical and political 

challenges that come with an integrated (meshed) 

European offshore grid. Furthermore, the investment 

needs are high. This raises the question of how to 

design an optimal offshore grid that minimises costs 

and maximises the benefits. 


1.2 Objective of OffshoreGrid 

To answer these questions, the OffshoreGrid project 

consortium developed a scientific view on an offshore 

grid along with a suitable regulatory framework that 

considers technical, economic and policy aspects. 

The study is designed to serve as background and 

supporting documentation for the preparation of further 

regulatory, legislative and policy measures. In 

particular, the outcomes are intended to provide input 

for the work on infrastructure by the European Union 

as outlined in the Second Strategic Energy Review, 

namely the Baltic Interconnector Plan, the Blueprint 

for a North Sea Offshore Grid and the completion of 

the Mediterranean ring [22] 4 . 

The OffshoreGrid study fulfils the following strategic 

objectives: 

• provide recommendations on methods for decisions 

on topology and dimensioning of an offshore 

grid in Northern Europe, 

• provide guidelines for investment decision and 

project execution, 

• trigger a coordinated approach for offshore wind 

connections with the Mediterranean ring. 

Related to its specific objectives, the project provides 

the following: 

• representative wind power time series, 

• a selection of blueprints for an offshore grid, 

• insight into the interaction of design drivers and 

techno-economic parameters, 

• analysis of the stakeholder requirements. 

The OffshoreGrid study is the first detailed assessment 

of this kind to give guidelines for the development of 

an efficient offshore grid design and is targeted towards 

European policy makers, industry, transmission 

system operators and regulators. 

4 The draft final report published in 2010 has already provided input to the European Commission for the Communication on ‘Energy 

Infrastructure Priorities for 2020 and Beyond’ [23]. 

5 The results have been applied to the Mediterranean region in qualitative terms. Although the potential for offshore wind energy is 

lower in the Mediterranean region than in Northern Europe, an in-depth analysis of the regional framework for offshore grids and 

electricity interconnection infrastructure is important, taking into account the need for interconnectivity and the long-term expectations 

for floating offshore wind turbines and solar thermal power in the region. More on this can be found in Annex E. 


1.3 Methodology & approach 

The techno-economic assessment is based on extensive 

market and grid modelling of the entire European 

power system accompanied by qualitative investigations 

of the political, legal and regulatory framework. 

In the preparatory phase, input scenarios on power 

generation capacity, electricity demand, commodity 

prices, grid development etc. were developed. A special 

focus was put on offshore wind power scenarios, 

where time series were developed with high temporal 

and spatial resolution. For other marine renewables 

and power demand from offshore oil and gas industry 

installations, estimates have been made based on literature. 

The plausibility of the scenarios was checked 

by extensive assessment of the political and regulatory 

environment in all relevant member states. 

In the modelling phase the input from the preparatory 

phase was used in a variety of techno-economic investigations. 

As a first step, different assessments for 

individual modules of an offshore grid – such as hub 

connections, tee-in solutions, hub-to-hub solutions – 

were carried out with a detailed cost-benefit analysis. 

In the second step an overall grid design was developed 

through an iterative process. 

The approach described above was carried out for 

Northern Europe (the regions around the Baltic Sea 

and the North Sea, the English Channel and the Irish 

Sea). This allowed the determination of an efficient 

offshore grid design supplemented by generic grid design 

rules for the North Sea region 5 . 

1.4 Stakeholders 

To assess, plan and build an offshore grid is clearly 

a multi-stakeholder process. From the very beginning 

the offshore grid consortium fostered an intensive exchange 

with the relevant stakeholders from politics, 

economics, industry and nature conservation. 

19

introduction 

TAblE 1.1: STAkEhOldERS PARTIcIPATING IN ThE STAkEhOldER AdvISORY bOARd 

Type of stakeholder Stakeholders involved in the SAB 

Regulatory Bodies Ofgem, Bundesnetzagentur 

Manufacturers Acciona Energia, ABB, Siemens AG, Nexans 

Project developers Transmission Capital, Mainstream Renewable Power 

Transmission System Operators 

Entso-E RG NS, Tennet, Energinet.dk, 50Hertz Transmission, 

Statnett 

European Commission EC DG TREN D1, EC BREC, EC DG TREN TEN-E, EC DG MARE, EACI 

Permitting and maritime spatial 

planning authorities 

Bundesamt für Seeschifffahrt und Hydrographie 

Utilities RWE Innogy 

Non-governmental organisations (NGOs) Greenpeace 

Fundamental scenario assumptions, the modelling approach 

as well as the preliminary and the final results 

were discussed in the Stakeholder Advisory Board 

(SAB), and the feedback was taken into account in the 

consortium’s work. 

All in all, three SAB meetings were organised. The 

participating stakeholders are shown in Table 1.1. 

Next to the SAB meetings, three Stakeholder 

Workshops (two Northern European workshops and 

one Mediterranean) have been held, open to anyone. 

In total, these were attended by 170 people from all 

stakeholder groups. 

Further presentation and discussion 

of results 

In addition, many other stakeholders were involved 

via several presentations at high level political and 

technical conferences, political working groups, several 

meetings with and workshops organised by the 

European Commission, bilateral meetings with manufacturers, 

ENTSO-E, etc. 

1.5 Document structure 

This document reports on the approach, methodology, 

results and recommendations of the OffshoreGrid 

project carried out between May 2009 and October 

2011. The document focuses on the results in order 

to increase comprehensibility and legibility. Extra and 

more detailed information on particular aspects such 

as, for instance, the applied models and the chosen 

scenarios can be found in Annex A to this final report 

on www.OffshoreGrid.eu. 

The analysis of OffshoreGrid is based on well defined 

energy scenarios explained in Chapter 2. The project 

methodology, the models and the interfaces are described 

in Chapter 3. 

Based on the chosen scenarios and models, a detailed 

techno-economic analysis was performed that led to 

the results illustrated in Chapter 4. This describes 

the aggregation of wind power over Europe, the costbenefit 

analysis of integrated design concept, and a 

possible offshore grid design for Northern Europe. 

This techno-economic assessment is accompanied 

by a qualitative assessment of the socio-economic 

drivers and barriers, the regulatory framework and the 

ongoing political discussions in Chapter 5. 

Chapter 6 summarises the conclusions and provides 

recommendations. An overall executive summary can 

be found at the very beginning of this document. 


TITle KEy ASSuMPTiONS AND ScENAriOS 

• Offshore wind development scenarios in Northern Europe 

• Generation capacity and commodity price scenarios 

• Technology to connect offshore wind energy 

Photo: C-Power

Key Assumptions and Scenarios 

In this chapter the key assumptions and scenarios 

used for OffshoreGrid modelling purposes are described. 

This includes the assumptions on: 

• installed capacities of offshore wind in Northern 

Europe, 

• electricity generation capacities, 

• electricity demand, 

• fuel and CO 2 prices. 

2.1 Offshore wind development 

scenarios in Northern Europe 

An important task in the OffshoreGrid project was the 

development of offshore wind power scenarios for the 

medium term (2020) and longer term (2030). They 

are mainly based on national government targets, on 

the latest EWEA offshore wind development scenario 

[20] and on the onshore wind power scenarios from 

TradeWind [24] updated with new available information. 

Figure 2.1 and Figure 2.2 provide an overview 

FIGURE 2.1: INSTAllEd cAPAcITY OF OFFShORE WINd FARMS IN NORThERN EUROPE TO 2030, OFFShOREGRId ScENARIOS 

UK 

Germany 

Netherlands 

Sweden 

Norway 

Poland 

France 

Denmark 

Belgium 

Ireland 

Finland 

Estonia 

Lithuania 

Latvia 

Russia 

0 5 10 15 20 25 30 35 40 45 

Wind farm capacity (GW) 

Installations 2021-2030 installations 2011-2020 Installed capacity, end 2010 

FIGURE 2.2: dISTRIbUTION OF INSTAllEd cAPAcITY PER SPEcIFIc MARINE AREA 

North Sea 

Baltic Sea 

Irish Sea 

English Channel 

Norwegian Sea 

Bay of Biscay 

Kattegat 

Atlantic (Ireland) 

Source: OffshoreGrid scenarios 

0 10 20 30 40 

Wind farm capacity (GW) 

50 60 70 80 

Installations 2020-2030 Installations until 2020 

Source: OffshoreGrid scenarios 


FIGURE 2.3: OFFShORE ANd ONShORE WINd FARMS INSTAllATIONS IN NORThERN EUROPE IN 2020 ANd 2030, OFFShOREGRId 

PROjEcT ScENARIOS 

OffshoreGrid 

Scenario 2020 

per country respectively per marine area 6 . Concrete 

figures and more explanation on the development 

of these scenarios can be found in Annex A.I and in 

Deliverable 3.2.b, available online [25]. 

The most important players in the offshore wind energy 

market in the medium term scenario will be the UK 

and Germany. This leading group is followed by France, 

Sweden, Denmark, Belgium and the Netherlands. Total 

installed capacity in Northern Europe is expected to be 

approximately 42 GW in 2020 and 126 GW in 2030. 

In the first phase, the major development of offshore 

wind capacity is expected to take place in the North 

Sea (Figure 2.2). An accelerated development of offshore 

wind farms in the Baltic Sea is expected to 

start after 2020. In 2020, the majority of wind energy 

installed capacity will still be onshore in most 

Northern European countries, except for the UK. In 

2030, more than 40% of total installed wind energy 

capacity in Northern Europe is estimated to be offshore. 

In the UK, Belgium, Netherlands, Baltic States 

and Scandinavian countries, most of the wind energy 

would then operate offshore. 

6 See Annex A.II for main assumptions regarding the scenario development. 


OffshoreGrid 

Scenario 2030 

Offshore wind electricity generation 

The 126 GW of installed capacity installed in 2030 

will produce 530 TWh of electricity annually. This is 

more than the overall annual electricity consumption 

of Germany (509 TWh in 2010). Over the life time of 

25 years the offshore electricity generation amounts 

to 13,300 TWh. 

2.2 Generation capacity and 

commodity price scenarios 

Offshore wind energy interacts strongly with the entire 

electric power system. Therefore, regional power 

markets have been analysed in order to elaborate the 

necessary input data for project modelling, such as: 

• electricity capacity scenarios for countries and regions 

regarded in the model, 

• electricity demand, 

• fuel price scenarios and CO 2 price scenarios. 

Electricity generation capacity 

One important input factor for the market and grid 

model is the installed electricity generation capacity 

and its future development. For this purpose, different 

23


FIGURE 2.4: ERGEG MARkET REGIONS 

■ Northern ■ UK & Ireland ■ Central East 

■ Central West 

■ Baltic 

■ South West ■ Central South 

national and transnational studies have been analysed 

and compared (e.g. [30][33]). The analysis of 

scenarios for electricity generation capacity includes 

information on the scenario years 2007/2008 as well 

as 2010, 2020, and 2030 for each of the 35 countries 

examined. As a result, a consistent data set for 

each country has been developed. 

In order to give an overview of the installed generation 

capacity within the ERGEG market regions, the country 

data were transformed into regional data for the seven 

regional electricity markets (Figure 2.4) 7 . Figure 2.5 

shows the developed electricity generation scenario. 

The OffshoreGrid study is based on a nuclear phaseout 

for Germany and is therefore in line with current 

political decisions 8 . 

Electricity demand 

For the OffshoreGrid scenario on electricity demand, 

the Primes 2009 Baseline scenario [33] is taken, 

completed with data from several national sources for 

the countries outside the EU. According to this source, 

FIGURE 2.5: dEvElOPEd ElEcTRIcITY GENERATION cAPAcITY ScENARIO FOR ThE ERGEG REGIONS (GW) 

Generation capacity (GW) 

500 

400 

300 

200 

100 

0 

2010 

2020 

Central- 

West 

2030 

2010 

2020 

2030 

Northern UK & 

Ireland 

Classi�cation unclear 

RES (other than hydro) 

2010 

2020 

2030 

Central- 

South 

Fossil fuel 

Nuclear power 

Central- Baltic 

East 

Hydropower 

(large scale + pump storage) 

7 For more information about the ERGEG market regions see www.energy-regulators.eu. 

8 The OffshoreGrid study is based on a nuclear phase-out for Germany according to the respective legislative act of 14 June 2000. 

The recent political decision requires the definite shut down of all nuclear units by 2022, somewhat earlier than previously decided. 

However, since OffshoreGrid only looks at the system in the years 2020 and 2030, this has no impact on the results, and it 

can be considered to be in line with the current political decisions. 

2010 

24 OffshoreGrid – Final Report 

2020 

2030 

2010 

2020 

South- 

West 

2030 

2010 

2020 

2030 

2010 

2020 

2030

FIGURE 2.6: cOMMOdITY PRIcES 

Prices (€2007/MWh) 

60 

50 

40 

30 

20 

10 

0 

gains in energy efficiency are offset by rising electricity 

consumption due to robust economic growth in 

Eastern and Southern European countries, hence the 

slight increase in electricity demand in the forecast for 

the next two decades. 

Fuel prices and CO 2 prices 

Figure 2.6 gives an overview of the chosen commodity 

price scenarios 9 . Lignite and hard coal prices remain 

relatively stable until 2030. Gas prices increase 

slightly. The sharpest increase in prices is expected 

for crude oil and CO 2 . 

CO2 [€ 2007/t] 

2.3 Technology to connect 

Gas EU 

offshore wind energy 

9 Detailed explanations of the chosen prices can be found in Annex A. For gas and lignite, national prices have been considered. 


2010 2020 2030 

Crude oil 35,4 44,9 53,8 

Hard coal 11,1 10,7 10,1 

Lignite EU 4,2 4,2 4,2 

Gas EU 21,5 23,8 24,6 

CO 2 (€ 2007/t) 23,0 36,0 44,4 

study takes into account possible future technology 

developments. The cost specifics of the equipment 

were elaborated in close cooperation with the main 

technology suppliers, and checked within the stakeholder 

workshops for plausibility. 

Thus the OffshoreGrid study had a complete portfolio 

of technologies to choose from, including detailed 

information on technical behaviour, as well as specific 

investment, maintenance and operation costs. 

It included different offshore and onshore transmission 

technologies as well as all relevant HVAC and 

HVDC technologies, switching equipment and substation 

technology. A more detailed overview is given in 

Annex B.I, available on www.offshoregrid.eu. 

Lignite EU 

Preferred technology for offshore wind 

connection 

The OffshoreGrid Hard consortium coal based its investigation The establishment of an extensive offshore grid link- 

on an in-depth technology analysis for onshore and ing countries across the North and Baltic seas, and 

Crude Oil 

offshore transmission equipment. Apart from the to a lesser extent the connection of offshore wind 

2010 2020 2030 

equipment that is available today, the OffshoreGrid farms to those countries, relies on High Voltage Direct 

crude oil 35,4 44,9 53,8 

hard coal 11,1 10,7 10,1 

lignite EU 4,2 4,2 4,2 

gas EU 21,5 23,8 24,6 

CO2 (€ 2007/t) 23,0 36,0 44,4 

25


Current technology. When considering the connection 

of the larger more distant offshore wind farms, the 

Voltage Source Converter (VSC) HVDC technology also 

becomes important. 

Compared to High Voltage Alternating Current technologies 

and even the Current Source Converter 

(sometimes called Line Commutated) HVDC technology, 

the VSC technology is relatively immature in 

terms of operating experience. The first onshore application 

of VSC technology was the 50 MW Gotland 

link (Sweden) commissioned in 1999, and the first offshore 

application was the 84 MW Troll A link (Norway) 

commissioned in 2005. Hence this technology has yet 

to be proven over the expected lifetime of an offshore 

wind farm or interconnector installation. 

Despite this lack of experience, the technical advantages 

that the VSC equipment provides for the 

connection and transmission of bulk power in the 

offshore environment means that the VSC equipment 

26 

will be the transmission technology of choice for large, 

distant offshore wind farms. It is for this reason that 

the majority of the offshore grid designs analysed in 

this report is based on VSC technology. 

However, current experience shows that the supply 

chain bottlenecks for the main components of HVDC 

technology can slow down the development of offshore 

wind farm connections. Therefore for singular 

cases it might be necessary to fall back upon AC connection 

concepts until the supply chain is fully able to 

deliver the requested equipment on time. 

OffshoreGrid – Final Report

METHODOLOGy – SiMuLATiON iNPuTS 

AND MODELS 

• Wind power series model 

• Power market and power flow model 

• infrastructure cost model 

• case-independent model 

Photo: C-Power

Methodology – Simulation inputs and Models 

The OffshoreGrid results are based on detailed generation 

modelling, market and grid power flow modelling 

and infrastructure cost modelling. Each of the modelling 

tasks is already a significant challenge in its own 

right and there is no integrated model that could solve 

the envisaged optimisation goal to determine an optimal 

offshore grid. The consortium therefore set up a 

stepwise methodology in which different models are 

combined in an iterative approach. All in all, four major 

models were developed and applied: the wind series 

power model, the power market and power flow model, 

the infrastructure cost model and the case-independent 

model. 

The wind series power model created wind power time 

series that fed into the power market and power flow 

model. This model was then combined with the infrastructure 

cost model in order to obtain results on case 

studies, to determine which offshore configuration 

was the most suitable. Output from these two models 

was also used in the case-independent model, which 

creates general overall conclusions that can be applied 

to most offshore scenarios. This design loop is 

illustrated in Figure 3.1. 

The following sections briefly describe the key features 

of each model. Annex C explains them in more detail. 

3.1 Wind power series model 

On- and offshore wind power have a predominant impact 

on the optimal grid design of an offshore grid. 

It was therefore decided to apply a specialised wind 

power model (meso-scale numerical weather prediction 

model) to generate high-resolution wind power 

time series for every offshore wind farm and every 

onshore wind region identified in the developed scenarios 

[25]. This was performed by first modelling the 

wind in the desired region, which was done through 

FIGURE 3.1: SchEMATIc EXPlANATION OF ThE INTERAcTION bETWEEN ThE MOdElS IN OFFShOREGRId 


cost model 

data collection and scenario development 

Power market and 

power flow model 

• Cost benefit results for different offshore grid building blocks 

• Fundamental design guidelines 

• Cost efficient overall grid design 

Wind series 

power model 

case-independent 

model 


use of the applied Weather Research and Forecasting 

Model (WRF) [1]. WRF is a meso-scale numerical 

weather prediction model, able to simulate the atmospheric 

conditions across a wide range of horizontal 

resolutions from 100 km down to 1 km. Once the WRF 

model runs were performed and validated, the wind 

speed time series at more than 350 offshore sites 

and 16,000 onshore grid points were determined. 

These wind speed time series were then converted 

to wind farm power generation, based on wind farm 

power curves. Power curves show the relationship between 

how much power will be produced from the wind 

farm under certain wind conditions. The resulting wind 

power time series are used as input to the power market 

and flow model described below. 

3.2 Power market and power 

flow model 

Power plants generate when they can sell their electricity 

to the market if there is enough grid capacity to 

transport it. The power market and power flow model 

[29] simulates the operation of the power system 

based on a detailed set of European generation data 

(capacity, costs, etc.) and a detailed European grid 

model. Both conventional power plants and renewable 

generation are modelled. 

The tool used to perform the modelling is called the 

Power System Simulation Tool (PSST) [2]. PSST combines 

a market model with a model of the European 

electricity grid, and assumes a perfect market with 

nodal pricing. The socio-economic optimum for the 

overall European electricity production is found by 

minimising the total yearly generation cost. From 

the simulations both technical and economic parameters, 

such as generation cost, energy prices, price 

differences and grid utilisation (off- and onshore) for 

different scenarios can be extracted. The results from 

this model together with the infrastructure cost model 

(see 3.3) allow decisions to be made on whether a 

specific offshore wind farm configuration is the most 

beneficial. 


3.3 Infrastructure cost model 

Building offshore grid infrastructure requires large investments. 

The extent of these investments is a key 

factor to be taken into account when determining the 

overall costs and benefits of the considered design. 

The infrastructure costing model [26][27] is used to 

determine the capital costing of the entire OffshoreGrid 

infrastructure used in the modelling phases, including 

individual wind farm connections, hub connections, 

wind farm tee-in connections, direct interconnectors, 

meshed hub-to-hub and hub-to-shore interconnectors, 

and split wind farm connections. It takes into account 

costs of different offshore cable and equipment technology, 

the cable length, sea depth, bathymetric data, 

project timing, onshore network security criteria, etc. 

The infrastructure cost model feeds directly into the 

net benefit model, together with the results from the 

power market model to assess the viability of links 

for arbitrage. The infrastructure cost model has two 

main stages, firstly incorporating a technical assessment 

of the required infrastructure to determine the 

required technology and then a costing exercise is performed 

to produce the capital costing for each wind 

farm connection. 

The costs produced by the infrastructure cost model 

are determined mainly by what technology is required 

and the connection distance. Following the calculation 

of the route lengths a technical assessment is 

made to determine the topology for each link. For wind 

farm connections and hub connections this could be 

either AC or DC depending on the distance. All interconnectors 

for arbitrage have been assumed to be 

HVDC due to the distances involved in connection. The 

technology available is based on which technology is 

commercially available today and future technology 

established in Deliverable 5.1, available online [26]. 

29

Methodology – Simulation inputs and Models 

3.4 Case-independent model 

During the course of the OffshoreGrid study it became 

apparent that the appropriate offshore grid design is 

very sensitive to the specific cases under investigation: 

distances to shore, wind farm capacities, price 

profile differences between the countries, etc. The 

results of the specific cases are useful but general 

conclusions are necessary for the optimal offshore 

grid design and also for clear recommendations, which 

is one of the central goals of the OffshoreGrid study. 

A case-independent model was therefore developed 

with inputs from the infrastructure model and the power 

system model. 

The model is built in the mathematical programming 

language Matlab and focuses on two design problems, 

namely the teeing-in of wind farms into an interconnector 

between two countries and the interconnection of 

two countries via two offshore wind farm hubs (these 

scenarios are described in more detail in Section 4). 

The model performs an extensive sensitivity analysis 

that looks into the impact of the price difference between 

countries, the direction of the price difference, 

the impact of cable or wind farm capacities, and the 

impact of cable lengths. The model then takes this information 

and produces general conclusions regarding 

the impact of changing one or more of the previously 

listed parameters on the viability of an offshore wind 

farm configuration. This allows the development of 

general offshore grid design rules, which are then validated 

using case studies. 


ResulTs 

• Wind output statistics 

• Wind farm hubs versus individual connections 

• integrated design – case studies 

• integrated design – case-independent model 

• Overall grid design 

Photo: Dong Energy

esults 

This chapter explains and summarises the results of 

the OffshoreGrid project. It focuses first on the statistics 

of the wind output (Section 4.1) when aggregated 

over larger regions via an offshore grid. The effect of 

smoothing is analysed, and concrete figures are provided 

on the correlation of the wind resource between 

countries, which is very useful for analysing the effect 

of interconnections. 

Secondly, an evaluation of wind farm hubs is carried out 

in Section 4.2. This section analyses in which cases 

and under which circumstances wind farms should be 

grouped in hubs before they are connected to the shore. 

The impact on connection costs for the developed offshore 

wind scenario is investigated. Furthermore, the 

risk of stranded investments is assessed. 

Section 4.3 analyses the possibilities for integrated 

designs, the basics of an offshore grid. The focus 

is put on two basic designs which form the building 

blocks of any future offshore grid design; the teeing-in 

of wind farms into interconnectors, and the interconnection 

of countries via offshore wind farm hubs. The 

section looks into specific cases. 

Average variation over 

time interval 

(% of maximum capacity) 

35 

30 

25 

20 

15 

10 

5 

With the help of a specially developed case-independent 

model, a thorough sensitivity analysis is done in 

Section 4.4. This leads to further insight into the drivers 

and concrete design guidelines. 

By means of a detailed iterative modelling process, 

taking into account the results from the previous sections, 

Section 4.5 shows what the offshore grid in 

Northern Europe could look like. Two design methodologies 

have been compared and lead to important 

conclusions on how to approach the modular building 

of an offshore grid. 

4.1 Wind output statistics 

4.1.1 Spatial smoothing of wind power 

There are several techno-economic benefits directly 

linked to an offshore grid as outlined in the introduction. 

One of these benefits is the additional interconnection 

of wind energy generation centres across Europe 

which smoothes wind energy variability giving it a 

FIGURE 4.1: AvERAGE vARIATION IN WINd POWER OUTPUT OvER dIFFERENT TIME INTERvAlS [% OF INSTAllEd cAPAcITY] 10 

0 

0 10 20 30 40 

Time interval for the variation (hours) 

Total 

Onshore (Total) 

BE+NO (offshore) 

UK (offshore) 

Offshore (Total) 

DE+UK (offshore 

NO (offshore) 

10 Note that a clear day-night pattern (24h interval) can be identified for the total onshore and total wind power production. 

DE (offshore) 

BE (offshore) 


steadier generation profile. This issue was already 

studied by the TradeWind study [2] and was further 

elaborated within OffshoreGrid as more accurate wind 

power time series were available. 

This spatial smoothing effect is illustrated in 

Figure 4.1, displaying the average variation (gradient) 

in wind power output over different time intervals. The 

longer the time interval, the higher the average variation 

is 11 . For the offshore wind farms in a small area as 

in the Belgian EEZ (Exclusive Economic Zone), the variation 

is relatively high already over one hour (4.9%), 

compared to a larger region like the EEZ of the United 

Kingdom (2.8%) or all onshore and offshore wind power 

in the OffshoreGrid scenario (1.1%). The differences 

increase with the length of the time interval. The average 

variation over 10 hours is only 7.2% of the total 

capacity for the total OffshoreGrid scenario, while for 

Belgian offshore wind power it is much higher (21.4%). 

It is important to highlight that this large-scale wind 

smoothing effect is only possible if power exchange 

can be realised across large areas and if the power 

exchange is not restricted. The grid plays a crucial role 

in interconnecting wind power plant outputs installed 

at a variety of geographical locations, with different 

weather patterns. The larger the grid and the larger 

its transmission capacity, the larger the smoothing effect 

of wind energy will be. This effect of course also 

holds for aggregation of demand or other weather 

or resource dependent generation technologies. A 

11 The average variation in output over one hour is obviously lower than the average change in output over a whole day. 


reduced variability brings numerous benefits to the 

power system, such as more technical stability and 

security, more stable prices, improved predictability 

and thus a more efficient operation which in its turn 

yields reductions in costs, primary energy consumption 

and emissions. 

The offshore grid will tremendously increase the transmission 

capacity over long distances and therefore 

largely contribute to the smoothing of wind power 

generation. 

A more detailed analysis of the wind power smoothing is 

shown in Annex D.I.I, available on www.offshoregrid.eu. 

4.1.2 Spatial power correlations 

Within OffshoreGrid a new way for visualisation of wind 

power correlations was developed in the so-called van- 

Bremen-maps. The idea is to calculate the correlation 

between time series of a certain local variable, like 

local wind speed at a specific point in space, and a 

prescribed reference time series. Then, all these correlations 

are plotted as a map for a high number of 

geographical points. In this way, the map shows the 

spatial characteristics of a specific correlation (for details 

please refer to Annex D.I.II). 

Figure 4.2 shows the correlation of the local wind 

power time series with either the simulated offshore 

wind power (figure to the left) or onshore wind power 

FIGURE 4.2: vON-bREMEN-MAP ShOWING SPATIAl cORRElATION bETWEEN lOcAl WINd POWER TIME SERIES ANd ThE 

SIMUlATEd TOTAl EU OFFShORE WINd POWER (lEFT) OR ONShORE WINd POWER (RIGhT) 

33

esults 

(figure to the right) in Northern Europe, as assumed in 

the 2030 scenario of OffshoreGrid: areas of low correlation 

are illustrated in blue, high correlation in red. 

The figures show that most of the offshore capacities 

in the 2030 scenario are concentrated in the southern 

part of the North Sea. In contrast to this, the onshore 

wind power in the scenario is more or less evenly distributed 

over Northern Europe. In total, wind energy is 

clearly concentrated in the North. This concentration 

will pose considerable challenges for power flows in 

the future European electricity grid. 

The correlation of the offshore wind power shows 

a clear west-east pattern: the figure on the left in 

Figure 4.2 reflects that the wind power production is 

more correlated from west to east than between north 

and south. Moreover the main wind direction is from 

west to east, especially the low pressure weather systems 

with strong wind speeds also move mainly from 

west to east. 

The analysis shows that grid interconnections between 

regions of low weather correlation can significantly 

reduce the variability of European wind power production. 

Interconnectors running in a north to south 

direction bring the highest benefit for the reduction of 

wind power variability. 

Spatial correlations of wind power 

production between countries 

With the simulated wind power time series, the spatial 

correlations between individual countries were also investigated. 

The results are shown in Table 4.1, which 

confirms the findings above. The correlations are 

highest in the east-west direction, for example a correlation 

of 74% between the UK and the Netherlands, 

67% between the UK and Germany, and still 29% between 

the UK and Poland. This is much less in the 

north-south direction, with correlations of only 44% 

between Norway and Denmark, 16% between Finland 

and Poland, and even only 5% between Norway and 

France. The combination Germany-UK yields higher average 

variations than a combination Norway-Belgium. 

This means that from a wind power variability point of 

view, a north-south interconnection between Norway 

and Belgium would be more beneficial than an eastwest 

interconnection between the UK and Germany. 

The figures in Table 4.1 can be used in the preliminary 

assessment of new interconnectors that are meant for 

trading wind power. Low correlation would hint at the 

need for new interconnecting capacity in order to fully 

utilise the variable wind resource. 

TAblE 4.1: cORRElATION cOEFFIcIENTS bETWEEN cOUNTRIES USING SIMUlATEd WINd POWER TIME SERIES FOR ThE 

OFFShOREGRId 2030 WINd POWER ScENARIO (ON- & OFFShORE WINd TOGEThER) (%) 

BE DK eT Fi Fr De uK IR lA lT Nl NO Pl Ru se 

BE 100% 45% 12% 2% 59% 67% 66% 37% 20% 21% 79% 12% 28% 20% 22% 

DK 45% 100% 32% 17% 32% 76% 49% 20% 44% 48% 77% 44% 78% 48% 73% 

eT 12% 32% 100% 51% 10% 18% 16% 12% 66% 66% 22% 13% 36% 45% 69% 

Fi 2% 17% 51% 100% 2% 6% 7% 4% 30% 34% 10% 23% 16% 19% 49% 

Fr 59% 32% 10% 2% 100% 37% 49% 43% 16% 18% 46% 5% 23% 17% 20% 

De 67% 76% 18% 6% 37% 100% 67% 26% 28% 30% 87% 40% 53% 32% 43% 

uK 66% 49% 16% 7% 49% 67% 100% 62% 20% 21% 74% 37% 29% 21% 27% 

IR 37% 20% 12% 4% 43% 26% 62% 100% 13% 14% 33% 14% 15% 13% 13% 

lA 20% 44% 66% 30% 16% 28% 20% 13% 100% 89% 32% 15% 55% 74% 69% 

lT 21% 48% 66% 34% 18% 30% 21% 14% 89% 100% 34% 17% 61% 88% 72% 

Nl 79% 77% 22% 10% 46% 87% 74% 33% 32% 34% 100% 36% 50% 34% 49% 

NO 12% 44% 13% 23% 5% 40% 37% 14% 15% 17% 36% 100% 24% 16% 30% 

Pl 28% 78% 36% 16% 23% 53% 29% 15% 55% 61% 50% 24% 100% 65% 73% 

Ru 20% 48% 45% 19% 17% 32% 21% 13% 74% 88% 34% 16% 65% 100% 59% 

se 22% 73% 69% 49% 20% 43% 27% 13% 69% 72% 49% 30% 73% 59% 100% 


–1 

–0.9 

–0.8 

–0.7 

–0.6 

–0.5 

–0.4 

–0.3 

–0.2 

–0.1 

–0

FIGURE 4.3: hUb cONNEcTION vERSUS INdIvIdUAl cONNEcTION 


Hub connection 

4.2 Wind farm hubs versus 

individual connections 

Within the last decade offshore wind energy development 

has accelerated significantly and today 

numerous wind farms are planned in the North Sea. 

Because of space restrictions due to maritime use 

conflicts and following the best wind potentials, many 

of these wind farms are planned far from shore and in 

close vicinity to one another in so-called offshore wind 

farm clusters. 

Immediately the question arose as to whether it is 

more efficient to bundle the electric connection of 

these wind farms at sea and carry the energy over 

a joint transmission line to the onshore connection 

points. This so-called hub connection (Figure 4.3) design 

can reduce costs, space use and environmental 

impact dramatically. 

The question of whether to build a hub to connect a 

number of wind farms with a shared line or whether 

to connect wind farms individually is the first question 

to be tackled when discussing a future offshore 

grid. Indeed, large wind farm hubs can form the basis 

for further interconnection to other countries and 

other wind farm hubs. The economic situation however 

Economic 

comparison 

Individual connection 

depends on a variety of parameters, such as wind 

farm distance to shore and wind farm sizes (rated 

capacity). 

An economic comparison of hub connection versus individual 

connections was carried out, with the results 

presented in the following sections. All offshore wind 

farms planned up to 2030 were considered. Based 

on economic considerations, it was decided whether 

every single wind farm will be integrated in a hub connection, 

or whether it is more economic to connect it 

individually. Please note that this assessment does 

not yet take into account additional country-to-country, 

hub-to-hub or tee-in interconnections. 

Wind farms are clustered and connected to offshore 

hubs, then connected to shore via shared transmission 

assets from these hubs. Detailed analysis shows 

that the advantages of hub connections strongly depend 

on offshore wind power siting in the different 

countries, that is to say the distance of each project 

from shore and from each other. 

35

esults 

4.2.1 Hubs and individual 

connections in the sea basins 

in Northern Europe 

The costs of a joint hub connection versus separate 

individual connections for the wind farm 

projects in the OffshoreGrid scenario have been 

assessed by using the hub assessment tool [26] 12 . 

The tool compares the costs of an individual connection 

with the costs of connecting the wind farm 

to a cluster nearby. 

12 For an economic analysis that takes into account time delays, please refer to section 4.2.3. 

Figure 4.4 shows the number of projects connected 

with individual connections to shore and those with 

a hub connection as a function of the distance of the 

wind farm to the onshore connection point of choice 

for an individual connection. The results have been 

detailed for the North Sea, Baltic Sea, Irish Sea and 

English Channel as well as by country. 

Sea basins 

The wind farms in the English Channel and Irish Sea are 

close to shore and rather widely scattered. Therefore 

the hub connection is not beneficial for any of them. 

All wind farms should be connected individually. 

FIGURE 4.4: FREqUENcY dISTRIbUTION OF PROjEcTS WITh INdIvIdUAl cONNEcTIONS TO ShORE ANd PROjEcTS cONNEcTEd vIA 

OFFShORE hUbS. OUT OF A TOTAl OF 321 PROjEcTS, 114 ARE cONNEcTEd vIA hUbS ANd 207 INdIvIdUAllY (2030) 

Number of 

wind farms 

30 

20 

10 

0 

Number of 


30 

20 

10 

0 

20 

20 

North Sea – Number of projects (individual vs hubs) 

40 

60 

80 

100 

120 

140 

160 

Hub distance to onshore connection point (km) 

Number in hubs Number not in hubs 

Baltic Sea - Number of projects (individual vs hubs) 

40 

60 

80 

100 

120 

140 

160 


180 

180 


200 

200 

220 

220 


240 

240 

260 

260 

280 

280 

300 

300 

320 

320 

More 

More

Number of 


30 

20 

10 

0 

Number of 


70 

60 

50 

40 

30 

20 

10 

0 

80 

70 

60 

50 

40 

30 

20 

10 

0 

20 

20 

Number of 

hub projects 

BE 


English Channel and Irish Sea – Number of projects (individual vs hubs) 

40 

All 2030 wind farms in the Northern sea Basins – Number of Projects (radial vs hubs) 

40 

Number and capacity of projects in hubs per country 

DK 

60 

60 

EST 

80 

80 

FI 

Number of WF in hubs 

100 

100 

FR 

120 

120 



DE 

140 

140 

UK 

160 

160 

IR 

180 


180 

Capacity in hubs 

LA 

200 

200 

LI 

220 


220 

NL 

240 

240 

NO 

260 

260 

PO 

280 

280 

Capacity of wind farms 

in hub (mw) 

RU 

300 

300 

320 

320 

SE 

25,000 

20,000 

15,000 

10,000 

5,000 

0 

More 

More 

37

esults 

The Baltic Sea is still a rather small sea basin and 

wind farms are mostly close to shore. Despite this, 

for 31 of the 92 wind farms in the Baltic Sea, a hub 

solution is beneficial. 

For the North Sea, the results reveal that hubs are 

particularly beneficial. With 83 hub connected wind 

farms, almost 50% of the 170 wind farms in the scenario 

are integrated in hubs. 

Hub wind farms per country 

The situation is very different across the European 

countries. While for Germany 19 hubs have been 

defined to which 59 of the total 70 German wind energy 

projects should be connected, hub connections 

are not beneficial in Ireland or Norway. This of course 

largely depends on the number of wind farms planned 

within the countries, the vicinity of these to each other 

and their relative distance and the distance to shore. 

In the United Kingdom and in the Netherlands, wind 

farms are often far from shore and concentrated in a 

few specific areas. Round 3 in the UK is a good example 

of this. These wind farms (e.g. Dogger Bank) have 

been assumed to be 1,000-2,000 MW each. They are 

indeed of the same size as the installed capacity of 

several wind farms in other European countries. This is 

a consequence of good siting and strategic planning. 

As a result of the hub assessment, 114 out of 321 

offshore wind projects have been clustered at hubs. 

Wind farms situated closer than 50 km to an onshore 

connection point are virtually always connected individually 

to shore. For wind farms situated between 50 

and 150 km from shore each option may be beneficial, 

depending on the total capacity in the surrounding 

area. For wind farms located further than 150 km 

away from an offshore connection point, the hub connection 

is almost always beneficial. The few individual 

connections found in this range are due to the solitary 

location of these wind farms. 

Hub size and distance to the hub 

The decision whether to connect wind farms via a 

hub not only depends on the wind farm’s distance to 

shore, but also on the total capacity of offshore wind 

within a reasonable distance of the hub location. 

The technological advancement of HVDC VSC assumed 

in this project based on several discussions 

with the manufacturers, indicates that a maximum 

hub capacity of 2,000 MW is a reasonable limit for 

2030 (see Annex B for further details). 

Due to economies of scale, small hubs are not viable 

far from shore. Figure 4.5 maps the distance of 

the wind farm projects to their hub versus the hub 

FIGURE 4.5: lARGEST dISTANcE FROM WINd FARM PROjEcTS TO ThEIR hUb FOR EAch hUb vERSUS hUb dISTANcE TO 

ONShORE cONNEcTION POINT. ThE bUbblE AREA REPRESENTS ThE hUb SIzE (MW). (hUb bASE cASE ScENARIO 2030) 

Project distance 

to hub (km) 

30 

25 

20 

15 

10 

5 

0 

0 50 100 150 200 250 300 

Hub distance to connection point (km) 

500 MW 1,000 MW 1,500 MW 2,000 MW 


distance to the onshore connection point. As can be 

seen from this figure, small hubs (< 500 MW) are not 

present for distances beyond 75 km. 

The largest distance from individual wind farms within 

the cluster to their hub is generally less than 20 km. 

Beyond a certain distance from the hub, AC technology 

is no longer economically viable for the connection 

of the wind farms to the hub. Therefore the use of 

AC/DC converters and an internal DC connected wind 

farm cluster is required. The fixed cost of these converters 

and associated platforms make such a hub 

arrangement less economic, and it has therefore not 

been assessed further. 

4.2.2 Overall cost reductions 

expected from shared connections 

via hubs 

Our analysis concludes that the connection costs for 

offshore wind farms up to 2030 can be reduced by 

€14 bn by sharing connections via hubs compared 

to a business-as-usual individual wind farm connection. 

Figure 4.6 shows a breakdown of the total grid 

connection costs for offshore wind power by country. 

The figure compares the scenario in which all wind 

25 

20 

15 

10 

5 

0 

13 As mentioned before, this is a consequence of the strategic planning and siting of offshore wind farms in the UK. The concessions 

are awarded in big lots, which leads to efficient individual connections. 


farms are connected with individual connections (radial 

connection scenario) to a scenario in which hub 

connections are allowed when beneficial (hubs base 

case scenario). 

Clustering of wind farms for hub connection is particularly 

beneficial in Germany, the United Kingdom 

and the Netherlands, where wind farms are often far 

from shore and concentrated in a few specific areas 

as discussed in Section 4.2.1. The largest achievable 

savings are €9.4 bn (34%) for Germany, €1.9 bn 

(8.7%) for the United Kingdom 13 , and €1.8 bn (22%) 

for the Netherlands. Also Finland and Poland can 

achieve considerable savings in relative terms, namely 

€270 m (15.8%) and €320 m (10.8%) respectively. 

In contrast, for other large countries such as France 

where offshore wind projects are dispersed along 

the northern coast line, there is no case for offshore 

hubs. Closer examination shows that offshore hubs 

are particularly beneficial when groups of wind farms 

are far from shore and close to each other. 

Taking into account all offshore wind farms to be 

built up to 2030 implies average connection costs 

of €660,000 per MW when using only individual connections 

and €550,000 per MW when using hub 

FIGURE 4.6: cAPITAl cOSTS FOR ThE GRId cONNEcTION OF OFFShORE WINd FARMS IN ThE RAdIAl REFERENcE ScENARIO 

(INdIvIdUAl WINd FARM cONNEcTIONS, cASE 1) vERSUS A ScENARIO WITh hUbS WhERE bENEFIcIAl (cASE 4); bREAkdOWN 

PER cOUNTRY (2030) 


cost (€ bn) 

30 

Belgium 

Denmark 

Estonia 

Finland 

France 

Hubs where bene�cial 

(Hubs base case scenario) 

Germany 

UK 

Ireland 

Latvia 

Lithuania 

Individual WF connections 

(radial reference scenario) 

Netherlands 

Norway 

Poland 

Russia 

Sweden 

39

esults 

connections to shore where this is beneficial. In 

Germany the average connection cost when using an 

individual connection is €1.06m per MW, while the 

connection cost is only €700,000 per MW when hub 

connections are considered. The reason for this is 

that connection points far inland have been selected 

in line with the dena Grid Study I [31]. Furthermore, 

German offshore wind farms are located relatively 

far from shore. In the German case, onshore cables 

represent 28% of the total connection costs for the 

radial reference scenario and 18% in the hub base 

case scenario. 

4.2.3 Scheduled wind farm 

connection – risk of stranded 

hub investments 

The hub connection of wind farms can thus be largely 

beneficial compared to the individual connection. 

However, the approach requires the coordination of 

the connection of two or more wind farm projects that 

are often owned and operated by different private entities. 

The primary challenge is that the hub has to 

be sized for the total capacity of all wind farms to be 

connected, even when only one farm is operational. 

The hub is therefore oversized until the missing wind 

farms are built, and this unused oversized capacity 

lowers the benefits of the project. For this reason 

the scheduling of the construction phase of the wind 

farms and the adherence to the schedule are crucial 

for the economics of the connection. 

In this context it is interesting to evaluate at what 

point such time delays render the project unviable. 

In particular it is crucial to assess what the costs of 

stranded investments are, which in this case includes 

the scenario where some of the wind farms that were 

planned to be connected to the hub are not built at all. 

These questions were studied for a theoretical case 

involving the connection of 3 wind farms of 350 MW 

each. These are located either 60 km (Case A) or 

150km (Case B) from shore, and both individual and 

hub connections were considered. The distances between 

hub and wind farms are assumed to be 10 km. 

For the two cases A and B, four subcases are developed 

(Figure 4.7). 

• Subcase 1 

Base case – Either all three wind farms are connected 

to the hub or they are connected to shore 

individually. All wind farms are built at the same 

time. 

• Subcase 2 

One of the three wind farms is not built. This means 

the hub is designed to connect three wind farms 

and is therefore oversized. In the case of individual 

connection, only the connections for the first two 

wind farms are built. 

• Subcase 3 

Similar to subcase 2. Here only one wind farm is 

built. 

• Subcase 4 

Wind farms two and three are built with a delay 

of 10 years. The hub is sized to connect all wind 

farms from the very beginning. In the case of individual 

connection the connections for the delayed 

wind farms are only built upon start of construction. 

For each of these cases and subcases, the costs were 

assessed by calculating the net present value of the 

investments. This was done by assuming a weighted 

capital interest rate of 6.6% and a depreciation period 

of 20 years, the typical design lifetime of a wind 

turbine. 

The result of these calculations is displayed in 

Figure 4.8. The following conclusions can be drawn: 

• Stranded investments – Wind farms not built: 

– even if one of the three wind farms is never built 

(subcase 2), a hub connection design is still 

beneficial compared to individual connection of 

two wind farms, 

– only if two of the planned wind farms are never 

built (subcase 3), the individual connection is 

economically preferable to the hub connection. 

• Delay in construction – temporary stranded investment 

(subcase 4): 

– even if the construction of the second and third 

wind farms is delayed by 10 years, the hub is still 

beneficial. The calculations have shown that the 

break-even point is reached at 12 years of delay. 


FIGURE 4.7: hUb cASES FOR ASSESSING cOSTS OF WINd FARM cONSTRUcTION dElAY ANd STRANdEd INvESTMENTS 

The results are a strong argument for hub connection 

and confirm the results of sections 4.2.1 and 4.2.2 

where hub solutions were found to be beneficial for 

a large number of offshore wind farms in the 2030 

offshore grid scenario. The case study further proves 

that the impact of stranded investments or temporary 

over-sizing is limited. 

FIGURE 4.8: cASE STUdIES ON TIME dElAYS ANd STRANdEd INvESTMENTS FOR hUb cONNEcTIONS 


Case A: 60 km 

- Wind farm capacity: 

350 MW each 

- Individual connection: 

270 m€ each 

- Spur costs: 

ca. 65 m€ each 

- Hub connection costs: 

415 m€ 

Case B: 150 km: 

- Wind farm capacity: 

350 MW each 

- Individual connection: 

360 m€ each 

- Spur costs: 

65 m€ each 

- Hub connection costs: 

525 m€ 

Costs (€m) 

2,500 

2,000 

1,500 

1,000 

500 

0 

Costs (€m) 

2,500 

2,000 

1,500 

1,000 

500 

0 

Subcase 1 

Hub 

Subcase 1 

Hub 

Subcase 1: 

All wind farms 

built in t=0 

The economic result is of course case dependent, 

with wind farm size and wind farm to hub connection 

distance playing a role in the outcome. However the 

cases here were chosen to cover a wide span of possible 

configurations. The results properly illustrate the 

fundamentals of the subject and allow the drawing of 

general conclusions. 

Costs of stranded investment Costs of delay 

of wind farms 

Subcase 2 


Subcase 2 


Subcase 2: 

Only two wind farms built 

Subcase 3: 

Only one wind farm built 

Subcase 3 

Subcase 3 

Subcase 4 

Subcase 4 

Subcase 4: 

Wind farm nr. 1 

built in t=0 

Wind farm 

nr. 2 and 3 

built 10 years later 

41

esults 

4.2.4 Conclusion and discussion on 

hubs versus individual connections 

Clustering of wind power projects is advantageous in 

many cases, depending on the distance from shore 

and the concentration of installed capacity in the 

same area. A shared hub connection is most advantageous 

when the sum of installed wind power capacity 

in a small area is relatively large and equal to standard 

available HVDC voltage source converter (VSC) 

systems. 

For distances from the onshore connection point of 

up to about 50 km, usually 50 Hertz HVAC technology 

is used and hubs do not generally provide much 

added value due to limited savings in cable length. For 

larger distances, the best solution depends primarily 

on the total available wind farm capacity in the area 

that could be grouped into the hub. For long distances 

to shore a hub connection is mostly beneficial; the 

benefit increases with distance. 

Integrating a wind farm into a nearby hub is economically 

advantageous for wind farm to hub connection 

distances of less than 20 km. For greater wind farm 

to hub connection distances the benefit will be rapidly 

reduced. However, if the hub’s size is large and 

if it is located far from shore, this again improves 

the economics. For wind farm to hub connection distances 

beyond 40 km, no beneficial hub cases were 

identified. 

In view of the large potential benefits of connecting 

wind farm clusters via hubs, political and regulatory 

strategies to foster their development are of primary 

importance. 

Additional considerations 

The above assessment is solely based on economic 

considerations. In cases where the hub is less beneficial, 

decision makers may still opt for hub solutions in 

order to mitigate the environmental and social impact 

of cable laying through environmentally sensitive or 

highly frequented coastal areas. A hub solution may 

also allow more efficient logistics during construction. 

Time delay costs and stranded 

investments 

It has to be highlighted that a hub project is in general 

more complex. Construction schedules of wind farms 

in a certain area seldom coincide. The economic assessment 

is based on their connection schedules. If 

projects that are supposed to be connected are abandoned, 

the overall hub costs increase significantly due 

to stranded investments or longer transition times 

with oversized cables that are only partly loaded. 

However, the case study analysis for a hub connection 

of three wind farms with a capacity of 350 MW each 

has shown that the costs of such delays or stranded 

investments should not be overestimated. In the case 

study the hub solution remains economically viable up 

to a 10 year time delay for two of the wind farms to 

be connected. Even if the one of the wind farms is 

not built at all, the hub connection is the preferred 

solution. 

Where hub connections are clearly shown to be beneficial, 

a dedicated regulatory and policy framework to 

mitigate this risk will be required. The risk of stranded 

investment can be mitigated, e.g., by strategic siting 

and concessions with the specific aim of having groups 

of projects with a capacity of 1,000 to 2,000 MW per 

group concentrated in an area and developed approximately 

at the same time. 

4.3 Integrated design – 

case studies 

This section elaborates on the integration of wind 

farm hubs and interconnectors, the main idea behind 

the offshore grid in the North Sea. The OffshoreGrid 

project focuses on two major design concepts. Any offshore 

grid design can be broken down into these two 

fundamental building blocks: 

• Teeing-in of wind farms into interconnectors (jointly 

developed with the wind farms or already existing) 

as shown in Figure 4.9. 

• Interconnection of countries via wind farm hubs on 

either side as shown in Figure 4.10. 


FIGURE 4.9: SchEMATIc REPRESENTATION OF A WINd FARM 

TEEd INTO INTERcONNEcTOR 

OffshoreGrid comes up with an understanding of the 

key design drivers. Based on a detailed cost-benefit 

analysis from the point of view of the European system, 

the viability and validity of various concepts has been 

investigated, aiming at an optimal balance between 

infrastructure size (and costs) and trade. By developing 

integrated solutions, the infrastructure costs are 

reduced, but at the same time constraints for electricity 

trade via the interconnectors are growing. 

4.3.1 Tee-in solutions – case study 

evaluation 

In trade-driven offshore grid development where power 

exchange between countries is the main driver for 

developing offshore transmission lines, connecting 

offshore wind farms to interconnectors can be a very 

interesting solution. In such a development, it can be 

considered to tee-in a nearby offshore wind farm already 

in the planning phase, or to make a provision for 

a later connection, if economically beneficial. 

Technically, the wind farm could be connected in two 

ways, either teed-in via an HVDC converter to the 

interconnector circuits, or via an HVDC switching 

station at the connection point (without convertor). The 

cases investigated here assume the straight tee-in 

solution, as these are less costly and are not reliant on 

new technology. However, the general conclusions and 

insights described in this section are also valid for 

the solution with HVDC convertors. More information 

on these technical issues can be found in Deliverable 

5.1 [26]. 

14 The Cobra cable case will be explained in further detail in paragraph 4.4.3. More background information and further details can 

be found in [27],[26], and [28]. 


FIGURE 4.10: SchEMATIc PRESENTATION OF bUIldING A 

cOUNTRY-TO-cOUNTRY INTERcONNEcTION bY cONNEcTING 

TWO WINd FARM hUbS 

Investigated cases 

The costs and benefits of a tee-in connection were 

investigated for three cases: 

• Connection of the German Bight wind farms, 

Sandbank 24 and Dan Tysk (800 MW) to the 

planned 1,400 MW Nordlink interconnector 

(NO-DE), 

• Connection of the wind farm Dogger Bank A 

(1,000 MW) to the planned 1,400 MW BritNor interconnector 

(NO-UK), 

• Connection of German wind farms (Butendiek 

(400 MW) / Nordsee Ost Group (1,300 MW)) into 

the planned 700 MW Cobra Cable (NL-DK). 

This section summarises the most interesting findings 

and results of the analysis for the Nordlink, BritNor 

and Cobra cables 14 . 

Reduction in infrastructure costs 

In all three cases, teeing-in the wind farm into the 

interconnector leads to a reduction in (combined) infrastructure 

cost. This is mainly because the cable to 

shore is longer than the cable to the tee-joint. 

The reduction that can be achieved depends largely on 

the wind farm capacity and the reduced wind farm connection 

cable length (= distance to the interconnector 

– distance to shore). For the connection of Dogger 

Bank A wind farm into the BritNor cable, €290 m in 

infrastructure costs can be saved compared to an 

individual connection. Teeing-in the Dan Tysk group 

into the NordLink cable can save about €160 m in 

infrastructure costs, while the teeing-in of Butendiek 

43

esults 

and NordSee Ost Group into the Cobra cable can 

save roughly €207 m and €280 m respectively (see 

Table 4.2). 

Reduction in system benefits 

However, while the infrastructure costs are reduced, 

teeing-in reduces the available capacity for electricity 

trade between two countries as the cables are now 

also loaded with wind energy. In each hour, the produced 

wind power from the teed-in wind farm will be 

sent to the country with the highest electricity price. 

The interconnector capacity for trading electricity from 

the country with the lowest price towards the country 

with the highest price is thus reduced, leading to 

a lower system benefit than in the case of a direct 

shore-to-shore interconnector. As can be seen from 

Figure 4.11, trade is only constrained more than in 

the Business As Usual (BAU=No Tee-in, wind farm connected 

to country A, direct interconnector built) case 

when electricity flows from country B to country A 15 . 

The reduction in system benefit happens in most 

cases, as is shown by the results for the BritNor and 

Nordlink cables. Teeing-in the Dogger Bank A wind farm 

into the BritNor cable increases the system costs over 

the lifetime by €400 m 16 , while the tee-in solution for 

the Dan Tysk group into the NordLink cable increases 

system costs by €63 m (Table 4.2). In some other cases, 

particularly when the wind farm is located in a third 

country with lower electricity prices, different results 

are obtained. This is shown in the Cobra cable cases, 

which will be further explained in Section 4.4.3. 

The eventual reduction in system benefits depends 

strongly on various parameters, such as the capacity 

of the interconnector cable, the capacity of the teed-in 

wind farm, the price difference between the countries, 

and the correlation between price difference and 

wind farm production over all hours. Additionally the 

overall trade, demand and generation situation in the 

European power system cannot be neglected 17 . 

Comparison and discussion 

Three of the four investigated cases have a net benefit 

for the European power system (Table 4.2). While the 

tee-in solutions on Nordlink and Cobra are beneficial, 

this does not hold for the BritNor Cable where over the 

lifetime there is no net benefit and additional costs 

of €110 m arise. In the latter case, the lower trade 

benefits are not outweighed by reduced infrastructure 

costs. The other three cases clearly have a lower significance 

for trade, and teeing-in the wind farms only 

leads to a relatively low reduction in system benefits. 

FIGURE 4.11: SchEMATIc EXPlANATION OF ThE REdUcTION OF SYSTEM bENEFITS bY TEEING-IN WINd FARMS INTO 

INTERcONNEcTORS, FOR TRAdE FROM cOUNTRY A TO b (lEFT) ANd FROM cOUNTRY b TO A (RIGhT). 

Trade constrained 


Trade unconstrained 


Prices Country A < Prices Country B Prices Country A > Prices Country B 

15 In the scheme on the top left of this figure, trade is in fact unconstrained and the wind flows into country A. However, from a system 

point of view this gives the same result as the scheme on the bottom left. 

16 Present value of a cash flow of yearly system benefits over a lifetime of 25 years and with a discount factor of 6%. 

17 In practice, as for direct interconnectors, the benefits are of course also dependent on future development of other interconnectors 

in the region. These improve market efficiency further and reduce the possible benefits of trading electricity due to a lower price 

difference. 


TAblE 4.2: SUMMARY OF ThE RESUlTS OF ThE TEE-IN cASES 

18 OffshoreGrid -- Stakeholder Advisory Board meeting, 21/01/2010, Brussels. 

OffshoreGrid -- 2nd Northern European Stakeholder Workshop, 10/06/2010, Brussels. 


infrastructure 

costs changes 

Additional system costs 

(over the lifetime) 

Net Benefit 

(over the lifetime) 

Dogger bank A into BritNor - €290 m + €400 m - €110 m 

Dan Tysk group into NordLink - €160 m + €63 m + €100 m 

Butendiek into Cobra - €207 m - €43 m + €250 m 

NordSee Ost group into Cobra - €280 m - €61 m + €341 m 

The principal conclusions from a sensitivity analysis 

of the effect of changing parameters on the net benefit 

are: 

• Asymmetrical cable dimensions can increase the 

system benefits. 

Increasing the capacity of one part of the interconnector 

(from the tee-joint position), can lead to 

better results. Capacity should then be increased 

at the side of the country with the highest prices 

(as trade flows towards the lower price level). A 

higher capacity would allow trade and parallel wind 

energy transport. The BritNor and NordLink cases 

demonstrate that asymmetrical cable dimensioning 

can increase trade possibilities to such an extent 

that the costs for larger infrastructure are more 

than compensated. 

• Tee-in benefits are largely dependent on wind farm 

sizes. 

To add a different solution the following case for 

the 1,000 MW Dogger Bank wind farm was investigated: 

500 MW were teed into the interconnector 

and 500 MW were connected directly to shore. 

It was shown that net benefits for this case are 

smaller in spite lower trade constraints on the interconnector. 

The reason is that in this case 500 

MW remain to be connected individually to shore, 

which is relatively more expensive than connecting 

a 1,000 MW wind farm (lower economies of scale). 

• Additional parallel trade interconnections can 

render a tee-joint more attractive than a direct interconnector, 

as price differences will be lower and 

trade less important. 

• The effect of an additional UK-NO interconnector 

on the cost-benefit of the tee-in solution for Dogger 

Bank A is investigated. This makes the combined 

UK-NO market more efficient and thus reduces 

the value of trade between both countries. The 

reduction in system benefits (economic trade constraints) 

is therefore lower, going from €400 m to 

€307 m. As this is still higher than the achieved 

reduction in infrastructure costs, the tee-in solution 

for Dogger Bank A is still not beneficial. 

This analysis demonstrates that the techno-economic 

relations are complex and that real cases do not allow 

generalised conclusions. Further in-depth analysis 

leading to such generalised conclusions is described 

in section 4.4. 

Practical discussion 

In terms of power system security, an interconnector 

cable with a wind farm connected in a tee-in 

configuration must be considered as one single asset. 

In case of a single fault anywhere on this asset, the 

interconnector plus wind farm would need to be isolated 

from the power system on both sides. Consequently, 

the power systems on both sides will experience a 

sudden change in power infeed, and contingency for 

this scenario must be considered according to the 

appropriate regulation. This may lead to an increased 

requirement for frequency reserves on either side of the 

tee-in, which should be considered before this option is 

recommended. It should be noted that discussion with 

representatives from some of the TSOs concerned 

during formal and informal stakeholder interaction 18 

have indicated that TSOs would prefer a solution with 

fast circuit breakers on a platform to a simple tee-joint, 

for reasons of operational security and fault handling. 

TSOs today have many years of experience with interconnectors 

based on Current Source Convertor (CSC) 

technology. The largest CSC Interconnector in Europe 

is rated at 2,000 MW and has been in operation since 

45

esults 

1986 (the Cross Channel link connecting France and 

Great Britain). In contrast, the experience with HVDC 

VSC technology is much shorter. The largest operational 

VSC interconnector is Estlink (350 MW, 2006). 

While equipment manufacturers expect VSC systems 

of up to 1,000 MW to be available in the coming years, 

it is likely that the VSC power capacity will remain lower 

than that available for CSC for the next ten years. 

The advantages of VSC over CSC technology are the 

ability to independently form a voltage reference which 

is very useful at an offshore hub for the connection of 

a wind farm, its compact size (and weight) compared 

to CSC, and its higher operational flexibility with regards 

to the direction of power flows. At present the 

converters do incur larger power losses than their 

CSC equivalents. In conclusion, the advantages of 

VSC technology in an offshore environment mean that 

it will be the HVDC technology of choice for the connection 

of offshore wind farms. However, for those 

interconnectors requiring a large capacity but not the 

specific features of VSC technology, the interconnector 

project developers will probably opt for the less 

experimental, higher commercially available capacity 

of CSC technology, particularly if no wind farm connections 

are anticipated in the short term. 

4.3.2 Hub-to-hub solutions – 

case study evaluation 

The development of interconnectors between wind 

farm hubs would be the beginning of a truly meshed 

offshore grid. Instead of connecting wind farms individually 

to shore and interconnecting the countries 

with a direct interconnection, the interconnection can 

be built between the wind farm hubs. The hub-to-hub 

solution implies that the offshore wind farms, along 

with their hub connection to shore, would be built first 

or in parallel with the hub-to-hub interconnector. This 

development may be considered wind driven as wind 

farm hub connections are the driver to install large 

HVDC VSC converters offshore with trade as a potentially 

beneficial add-on. This is similar to the option of 

dividing the wind farm connection in order to connect 

to two countries as discussed in Section 4.3.1, but 

is in contrast to the option of connecting wind farms 

to planned interconnectors where international power 

exchange is mostly the key driver. 

Technically, to operate efficiently a complex multi-terminal 

meshed configuration is likely to require the use 

of HVDC VSC technology and the availability of fast 

HVDC circuit breakers in order to limit the propagation 

of faults throughout the whole network. Equipment 

manufacturers have confirmed to the OffshoreGrid 

FIGURE 4.12: PROTOTYPE GRIdS WITh dIFFERENT cONFIGURATION IllUSTRATING ThE APPROAch FOR cOMPARISON OF REAl 

SITUATIONS IN ThE cASE STUdY [3] 

Country A Country B Country A 

Country C 

Country B 

Country C 

(a) hubs with integrated interconnectors (b) hubs and point-to-point interconnectors 


consortium that they will be bringing such components 

on the market within the next few years 19 . 

Manufacturers have already offered these assets 

to commercial projects but no contracts have been 

awarded yet. The integrated solutions proposed here 

do not rely on the use of fast HVDC breakers, although 

these can be added to increase security of supply. 


The cost-benefit analysis of hub-to-hub connections 

has been done with reference to the Hub Base Case 

2030, in which wind farms are connected to hubs 

where beneficial (compare Section 4.2). Infrastructure 

costs and system benefits have been calculated in 

three case studies for a situation with interconnectors 

between offshore hubs (thus becoming integrated 

offshore grid nodes). The results were then compared 

to a situation where the onshore connection points 

of the respective offshore hubs are connected by an 

interconnector of the same capacity. The principle is 

illustrated in Figure 4.12. 

Integrated hubs have been compared to point-to-point 

connections for the following cases: 

• Great Britain to Continental Europe (Germany) by 

interconnecting the Dogger Bank E hub with the 

Gaia hub, 

• Great Britain to Norway by interconnecting the 

Dogger Bank A hub with Idunn, 

• Triangular interconnection: Norway – Great Britain 

– Germany between the hubs Idunn (NO) -- Dogger 

Bank A (UK), Dogger Bank E (UK) -- Gaia Group (DE) 

and Horizont Group (DE) – Aegir (NO). 

19 OffshoreGrid – 1st Northern European Stakeholder Workshop, 14/09/2009, Stockholm. 

OffshoreGrid -- Stakeholder Advisory Board meeting, 21/01/2010, Brussels. 

OffshoreGrid -- 2nd Northern European Stakeholder Workshop, 10/06/2010, Brussels. 


Reduction in infrastructure costs 

In all three cases interconnecting countries via the 

wind farm hubs leads to a reduction in infrastructure 

cost compared to individual connections and a direct 

interconnector. 

Infrastructure costs for the integrated solution are in all 

cases 70 to 80% lower than for the respective solution 

with direct lines. The ratio reflects mainly the savings 

in numbers of converters and cable costs, due to the 

use of the wind farm hubs and the shorter distances 

to cover with the integrated solution, respectively. For 

the UK-Germany interconnection, the cost reduction is 

about €693 m. For the UK-Norway interconnection it 

is €600 m, while for the triangular interconnection the 

total infrastructure cost reduction compared to direct 

interconnections amounts to €1.9 bn. 

Reduction in system benefits 

The system benefit for the integrated solution is always 

lower than for the direct line solution, due to 

the constraint on international power exchange. As 

can be seen from Figure 4.13, the interconnector 

between the hubs can be regarded as equally constrained 

as a direct interconnector would be. The 

trade is only constrained more than in the BAU case 

because of the wind farm connection in the country 

with the highest prices (red line in Figure 4.13). If the 

cable capacities are the same for both countries, this 

is of course identical when the price in Country A is 

higher than in Country B. 

In relative values comparing to the system benefits 

in the direct line solution, the system benefits of a 

FIGURE 4.13: SchEMATIc EXPlANATION OF ThE REdUcTION OF SYSTEM bENEFITS WITh hUb-TO-hUb INTERcONNEcTORS, FOR TRAdE 

FROM cOUNTRY A TO b. ThE REd lINE ShOWS WhERE ThE SYSTEM cONSTRAINTS ARE INcREASEd 

Prices Country A < Country B Prices Country A < Country B 

47

esults 

UK-Germany connection are reduced by €585 m. For 

the UK-Germany interconnection, the system benefits 

are reduced by €416 m, while for the triangular interconnection 

the system benefits are reduced by €1.06 

bn compared to a direct line solution. 

Comparison and discussion 

As shown in Figure 4.14, the net benefit is positive 

for all three cases, although differing in absolute numbers. 

Especially for the UK-Germany connection and 

the triangular solution, significant benefits can be obtained 

by developing the integrated solution. In the 

UK-Norway case, the reductions in both trade and in 

investment costs are equal, hence the net benefit is 

low. So, in this case the hub-to-hub solution will not be 

built, unless, for instance, one of the interconnector 

legs get a higher capacity to reduce trade constraints. 

The case for hub-to-hub connections depends strongly 

on the demand for international power exchange between 

the market areas on each side. A first order 

sensitivity analysis leads to the following observations: 

• With higher price differences between the countries, 

the benefits of an extra interconnector 

increase, both with a direct interconnector as with 

an interconnector between hubs, 

FIGURE 4.14: SUMMARY OF RESUlTS OF hUb-TO-hUb SOlUTION cASE STUdIES 

Costs/bene�ts 

(€m) 

2,000 

1,800 

1,600 

1,400 

1,200 

1,000 

800 

600 

400 

200 

0 

UK-NO 

UK-DE 

Reduced bene�ts Reduced costs 

• With lower price differences (e.g. due to an additional 

direct interconnector), the benefits of a 

hub-to-hub interconnector may still exist, but are 

reduced. 

When there is demand for international power exchange 

capacity, an integrated hub-to-hub solution can 

be more beneficial than an additional point-to-point 

interconnector, particularly if the hub-to-hub interconnection 

yields significant savings in cable length. The 

investigated cases clearly show that there are opportunities 

which can significantly increase the net 

benefit from a European point of view. This was the 

case for the UK-Germany interconnector as well as for 

the triangular meshed solution. 

However, since developing a hub-to-hub interconnector 

between hubs implies trade constraints, the net 

benefit of direct interconnectors increases faster than 

the net benefit of hub-to-hub interconnectors. Indeed, 

the infrastructure costs remain the same but the 

economic impact of trade constraints increases if the 

price difference is larger. 

In the UK-Norway case price differences are larger, 

so that interconnectors are more beneficial between 

these countries. Because of this, the trade constraints 

in a hub-to-hub solution become more important, and 

the net benefit over a direct solution is much smaller. 

UK-NO-DE 

Net bene�t 

(€m) 

Net bene�t (right axis) 


900 

800 

700 

600 

500 

400 

300 

200 

100 

0

The higher the price difference between countries, the 

more important the trade constraints become. 

Trade constraints can be reduced by optimal dimensioning 

of each of the different elements. This is 

different in each case, and depends on the distances 

from shore, the distances between the hubs, the price 

difference profiles between the countries, and the capacity 

of the wind farm hubs. 

4.4 Integrated design – 

case-independent model 

As was shown in the previous section (4.3), numerous 

parameters influence the results. They are very 

case-specific, which makes it difficult to draw general 

conclusions. On the other hand, general conclusions 

are indispensible for offshore grid planning, the supporting 

policy making process and also for the project 

developers themselves. Such conclusions for caseindependent 

concepts have been derived with help of 

a dedicated “offshore grid design assessment model”. 

With this model, the tee-in solutions and the integrated 

hub-to-hub solutions are further assessed and concrete 

guidelines are developed in the following paragraphs. 

Finally, a practical case study has been elaborated 

to check the results against a well advanced real 

case. The Cobra cable – a direct interconnector cable 

planned between Denmark and the Netherlands – has 

been chosen because the consortium considers this 

a very important and relevant project in the process 

towards an offshore grid (paragraph 4.4.3). 

General analysis 

The results of the cases presented in section 4.3 

are very context-specific and thus not generally applicable. 

The present section aims at developing more 

general conclusions and understanding about the key 

design drivers based on a thorough sensitivity analysis 

with a dedicated offshore grid analysis model, 

that investigates under which circumstances an integrated 

solution is beneficial over a BAU solution. The 

approach focuses on two principal design optimisation 

problems considered to be the modular building 

blocks for any international offshore grid design: 


• Break-even distance wind farm (WF) to shore beyond 

which a tee-in solution is beneficial: 

– the larger the distance from the wind farm to 

shore, the more cable length can be saved by 

going for a tee-in solution, 

– the closer to shore, the more the constraints 

that it introduces will be important, 

– depending on various parameters, there is a 

minimum distance (break-even distance) from 

the wind farm to shore beyond which a tee-in 

solution becomes preferable over a conventional 

individual connection and direct interconnector. 

• Break-even distance between hubs below which a 

hub-to-hub solution is beneficial: 

– the shorter the distance between hubs, the 

more infrastructure costs can be saved by going 

for a hub to hub solution instead of a separate 

direct interconnector solution, 

– the larger the wind farms (respectively the hubs), 

the more the trade constraints that it introduces 

will be important, 

– depending on various parameters there is a maximum 

distance (break-even distance) between 

the hubs up to which it is preferable to choose 

a hub-to-hub solution over a conventional individual 

connection and direct interconnector. 

Concrete results that can be used by project developers, 

consultants, political decision makers, regulators, 

etc. are available on www.offshoregrid.eu. 

4.4.1 Minimum distance for 

tee-in solution 

Introduction 

Figure 4.15 and Box 1 explain the optimisation 

problem. The objective is to calculate the break-even 

distance from the wind farm to shore beyond which a 

FIGURE 4.15: EXPlANATION OF ObjEcTIvE: MINIMUM dISTANcE 

WINd FARM TO ShORE FOR TEE-IN SOlUTION 

Separate better 

Tee-in better 

49

esults 

tee-in solution becomes preferable over a conventional 

connection of the wind farm to shore. For wind-farm-toshore 

distances lower than this minimum distance, a 

conventional solution is preferable. For larger distances, 

a tee-in solution is better. 

An example (parameters are given in figure caption) 

of the general results of the calculations is shown in 

Figure 4.15 and is explained below: 

• For low wind farm capacities (Area A) smaller than 

the interconnector capacity the break-even distances 

for tee-in are low, but increase with wind farm 

capacity. 

The trade constraints induced by the wind farm are 

low in this capacity range. The reduction in wind 

farm connection cost is thus dominant and makes 

tee-in solutions beneficial even with relatively modest 

distances. 

• For larger wind farm capacities (between 1x and 

2x the interconnector capacity) (Area B) the breakeven 

distance is relatively low and decreases 

with wind farm size. The savings in infrastructure 

cost increase faster than the losses of the trade 

constraints. 

Box 1: Explanation of the optimisation 

problem for tee-in solutions 

Tee-in solutions – break even distance 

• If the wind farm to be teed-in is far from shore, 

then the individual connection of the wind farm 

would be long compared with the relatively short 

length of the tee-in cable. 

� Tee-in here produces large infrastructure 

costs savings. 

• If the wind farm to be teed-in is large, the 

interconnector cable will be constrained. 

� These trade constraints result in loss of 

system benefits. 

To evaluate the break-even distance, which is 

the minimum distance of the wind farm to shore 

beyond which it is beneficial to tee-in: 

• Low minimum distance means: Tee-in solutions 

are very beneficial, even for small distances. 

• High minimum distance means: Tee-in solutions 

are only interesting for wind farms far from shore. 

FIGURE 4.16: EcONOMIc bREAk EvEN WINd FARM TO ShORE dISTANcE FOR A TEE-IN SOlUTION (kM) FOR dIFFERENT WINd 

FARM SIzES. (INTERcONNEcTOR cAPAcITY OF 500 MW, AvERAGE AbSOlUTE PRIcE dIFFERENcE OF €7.5, dISTANcE WINd FARM 

TO INTERcONNEcTOR OF 40kM, UNbAlANcEd FlOW WITh 30% OF PRIcE dIFFERENcE FlOWING TOWARdS ONE cOUNTRY) 20 

Minimum needed 

distance WF-shore (km) 

400 

350 

300 

250 

200 

150 

100 

50 

0 

100 

200 

A B 

C 

300 

400 

500 

600 

Tee-in beneficial 

BAU beneficial 

Capacity of the wind farm (MW) 

20 The curve shows some gradients which were initially not expected. It is not smooth because of the nature of the infrastructure cost 

tables (cheaper for standard sizes) and the nature of the duration curve of the wind power production (nonlinear curve showing 

that a wind farm operates more often with medium power output than with maximum or zero output). 


700 

800 

900 

1,000 

1,100 

1,200 

1,300 

1,400

TAblE 4.3: SUMMARY OF FINdINGS ANd INSIGhTS FROM SENSITIvITY ANAlYSIS ON ThE MINIMUM dISTANcE WF-ShORE 

FOR TEE-IN SOlUTIONS 

impact on the minimum distance wind-farm-to-shore for tee-in solutions 

Sensitivity analysis factor 

to be beneficial over the business as usual case. 

Interconnector capacity • Larger interconnector capacities reduce the benefit of tee-in solutions over 

the BAU case. 

• For wind farm capacities lower than the interconnector capacity, there is no 

impact. 

• For interconnector capacities larger than twice the wind farm capacity, 

energy is lost (cannot be transmitted) and this reduces the benefit of tee-in 

solutions. 

Distance WF-interconnector • The further a wind farm is located from an interconnector, the less beneficial 

it is to tee-in to it. 

Absolute price difference • The higher the absolute difference of price levels in the connected countries, 

the more important electricity trade becomes and the less beneficial tee-in 

solutions are. 

Electricity price profiles • If the price difference is not balanced, the impact of wind power production 

becomes larger. Depending on the usual direction of the price difference, teein 

solutions are less beneficial (when the price is most of the time higher in 

the original wind farm country) or more beneficial (when the price is most of 

the time higher in the other country). 

Wind power correlation • If the price difference is lower when there is a lot of wind, the impact of constraining 

the cable will be less important and tee-in solutions become more 

beneficial. 

• For wind farm capacities higher than double the 

interconnector size (C), the break-even distance increases 

rapidly with wind farm capacity. 

Any power production which exceeds the interconnector 

capacity will be dissipated and lost. These 

energy losses have a high cost and result in a 

steep rise of the curve. 

Two points on the graph are of specific interest: 

• Wind farm capacity = interconnector capacity 

There is a peak in the curve at the capacity of the 

interconnector cable (500 MW in Figure 4.16). The 

reduction of infrastructure cost is rather low while 

the trade constraints are already rather high. It is 

the least efficient wind farm capacity to be teed-in 

(Area C excluded). 

• Wind farm capacity = 2x interconnector capacity 

When the wind farm is double the capacity of the 

interconnector cable, the interconnector cable acts 

as a connection of the wind farm to two countries. 

Please note that the connection cables that form 

the interconnector via the wind farm taken together 

still have the full capacity of the wind farm. At high 

wind generation the full wind energy can thus be 

transported to shore and no wind energy has to be 

curtailed. The additional infrastructure costs are in 

21 This can for example be an offshore wind farm near oil plaforms or on small sandbanks close to an interconnector. 


this case low compared to a normal individual connection. 

It is an extreme case where the possibility 

to trade electricity is almost for free as the wind 

power would have to be connected anyway. 

In the following chapters, this connection concept in 

which one wind farm is connected to two shores (split 

connection) is called a split wind farm connection. 

Sensitivity analysis 

An extensive sensitivity analysis is performed on 

these results, which is summarised in Table 4.3. More 

details from the sensitivity analysis with detailed 

graphs can be found in Annex D.II.I which is available on 

www.offshoregrid.eu. 

Conclusions 

In the following situations, it is recommended to investigate 

the economic case for tee-in solutions: 

• Small wind farms (

esults 

• Large wind farms (capacity approximately 2x interconnector 

capacity). 

Teeing-in large wind farms may constrain trade, but 

the reduction in infrastructure costs is more important. 

The break-even distance to shore is therefore 

low (Figure 4.16). 

The second conclusion can be interpreted further. 

Instead of connecting big wind farms to the country 

where they are located, they could be connected with 

smaller connection capacities to two countries. With 

more or less the same investment costs (if the wind 

farm is located roughly in the middle), an interconnector 

is created at the same time 22 . This interconnection can 

be used when the wind power produced is less than 

50% of the capacity (about 55-60% of the time). The 

Box 2: Explanation of the optimisation 

problem for hub-to-hub solutions 

hub-to-hub solutions – break even distance 

• If the wind farm hubs are close to each other, 

the hub-to-hub cable that creates a hub-to-hub 

interconnector is short compared to the length 

of a separate shore-to-shore interconnector. 

� The hub-to-hub solution results in large infrastructure 

cost savings. 

• If the wind farm hubs are large the wind energy 

will constrain the trade. 

� These trade constraints result in loss of system 

benefits. 

To evaluate the break-even distance, which is the 

maximum distance between hubs below which it is 

beneficial to interconnect via the hubs instead of 

building a direct interconnector: 

• Low maximum distance means that hub-to-hubsolutions 

are not interesting, or only interesting 

for hubs very close to each other. 

• High maximum distance means that hub-to-hubs 

solutions are very interesting, even for hubs further 

from each other. 

22 In these cases, trade is a pleasant by-product of the connection of the wind farm. 

23 A sensitivity analysis on this is performed and described further. 

FIGURE 4.17: EXPlANATION OF ObjEcTIvE: MAXIMUM dISTANcE 

bETWEEN hUbS FOR hUb-hUb SOlUTION 

Direct better 

Hub-to-hub 

better 

additional infrastructure costs consist mainly of extra 

connection cable length to the second country plus the 

equipment to couple both cables to the offshore wind 

farm. This needs to be compared to the additional system 

benefits, which are the result of the possibility to 

send wind power to the highest price area and to use 

the spare capacity for extra trade. In conclusion, this is 

a very interesting option for large wind farms far from 

shore (e.g. UK round 3). However, it introduces political 

and regulatory problems (not all wind will flow into the 

country that pays support) which need to be solved. 

4.4.2 Maximum distance between 

hubs for integrated hub solution 

Introduction 

Figure 4.17 and Box 2 explain the optimisation problem. 

The objective is to calculate the break-even 

distance between the hubs up to which a hub-to-hub 

solution is preferable over the conventional connection 

of the hub to shore. For hub-to-hub distances 

lower than this maximum distance, the saved costs 

outweigh the trade constraints and a hub-to-hub solution 

is preferable. For larger distances between the 

hubs, the infrastucture cost reduction is not large 

enough to balance the trade constraints and a direct 

hub-shore connection plus separate interconnector is 

better. 

As an initial hypothesis it is assumed that 23 : 

• the wind farm hubs at either side have the same 

capacity; 

• the rated capacity of the connection cable from hub 

to shore is equal to the rated wind farm capacity. 


FIGURE 4.18: MAXIMUM dISTANcE bETWEEN hUbS TO MAkE hUb-TO-hUb SOlUTION MORE bENEFIcIAl ThAN dIREcT 

INTERcONNEcTOR FOR dIFFERENT WF cAPAcITIES [kM] (INTERcONNEcTOR cAPAcITY OF 500 MW, AvERAGE AbSOlUTE PRIcE 

dIFFERENcE OF €5, dIREcT INTERcONNEcTOR dISTANcE 500 kM, UNbAlANcEd FlOW WITh 30% OF PRIcE dIFFERENcE 

FlOWING TOWARdS ONE cOUNTRY) 

Maximum distance 

between hubs (km) 

600 

500 

400 

300 

200 

100 

0 

Figure 4.18 provides relevant insight and understanding 

into the drivers of this concept: 

• Area A: the wind farms and their connections to 

shore are smaller than the interconnector capacity 

(in this case 500 MW). The hub-to-hub interconnector 

is therefore oversized, and the hubs need to be 

close together to make it beneficial over a conventional 

solution. 


100 

200 

Area A 

300 

400 

500 

600 

700 

800 

Direct interconnector is preferable 

Hub-to-hub solution is preferable 

900 

1,000 

1,100 

Area B 

1,200 

1,300 

1,400 

Wind farm hub capacity (on either side) (MW) 

1,500 

1,600 

• Area B: The larger the wind farm hub capacity (and 

thus its connection to shore) compared to the 

interconnector capacity, the less constrained the 

system is. The inter-hub distance can be larger 

to still benefit from hub-to-hub connection instead 

of the combination of individual wind farm connections 

and a direct interconnector. 

TAblE 4.4: SUMMARY OF FINdINGS ANd INSIGhTS FROM SENSITIvITY ANAlYSIS ON ThE MAXIMUM dISTANcE bETWEEN hUbS FOR 

hUb-TO-hUb-SOlUTIONS 


factor 

Interconnector 

capacity 

Distance direct 

interconnector 

Absolute price 

difference 

Electricity price 

profiles 

Wind power 

correlation 

Asymmetrical WF 

capacities 

impact on the maximum distance between hubs for hub-to-hub solutions to be 

beneficial over a direct interconnector. 

• Larger interconnector capacities reduce the benefit of hub-to-hub solutions over the 

BAU case. 

• For wind farm capacities which are smaller than the interconnector capacity, the wind 

farm connections are the constraining factor for trade. 

• Increasing the interconnector capacity further only leads to additional infrastructure 

costs and thus lowers the maximum beneficial distance. 

• The larger the distance between two countries (= direct interconnector length to 

which it is compared), the more infrastructure costs will be saved by interconnecting 

hubs, and thus the more beneficial hub-to-hub solutions are. 

• The higher the absolute difference of price levels in the connected countries, the 

more important electricity trade becomes and the less beneficial hub-to-hub solutions 

are. 

• Unbalanced price profiles have no impact. This is due to the fact that the constraints 

on the cables are independent of the direction of the price difference when cable capacities 

are identical (as explained in section 4.3.2 (paragraph on system benefits). 

• If the price difference is lower when there is a lot of wind, the impact of constraining 

the cable will be less important and hub-to-hub solutions become more beneficial. 

• Imagine that the wind farm in country A is 50% smaller than the wind farm in country 

B. When prices are more often higher in country B, trade is less constrained which 

makes hub-to-hub solutions more beneficial. 

1,700 

1,800 

1,900 

2,000 

53

esults 

• Very large wind farm hubs may even be close to 

the shore and still have a positive net benefit for 

interconnecting between them instead of installing 

a direct interconnector. This is for two reasons: 

– the interconnector cable (established via the 

hub-to-hub connection) is less constrained by 

the wind farm connection cables as these have 

larger capacity, and 

– although there is need for extra equipment 

offshore, no onshore substation and onshore 

equipment are needed. 


An extensive sensitivity analysis is performed on 

these results. A summary is given in Table 4.4. More 

details from the sensitivity analysis with clear graphs 

can be found in Annex D.II.II on www.offshoregrid.eu. 

Conclusions 

The case-independent model confirms that hub-to-hub 

solutions can be beneficial, and provides concrete guidelines. 

In general, the following conclusions are important: 

• If the capacity of the hub-to-hub interconnector is 

small, it will help to send the electricity from both 

wind farms to the highest price area. Larger interconnector 

capacities are interesting when the price 

difference between the countries is high, but they 

should not exceed the connection capacity of the 

wind farms to the onshore point of connection. 

• If the price difference between both countries 

is not balanced, it is worth over-sizing the shoreconnection 

of the wind farms to the country which 

FIGURE 4.19: IdENTIFIEd SEvEN cASES 

usually has the highest price during the lifetime 

of the interconnector, and under-sizing the hub-toshore 

connection to the other country. This way the 

electricity can flow to the area with higher prices. It 

is the most optimal solution for overall European 

welfare. 

• For meshed grid nodes with more than two lines 

coming together, similar conclusions can be drawn. 

The links to the country with the highest prices 

(over the lifetime of the interconnector) should be 

largest, and the other ones can be dimensioned 

smaller. The most efficient solution would occur if 

the sum of all country connection cable capacities 

equals the sum of the connected wind farms. This 

way the additional investment in integrated platforms 

and joints brings interconnection between 

three countries. If larger interconnection capacity is 

needed, some of the cables can be over-sized. 

The case-independent model can be used to provide 

quick support to find a tailor-made solution out of the 

many possible configurations. The analysis in this 

section demonstrates the possibilities of choosing 

the optimal solution by taking into account various 

factors such as the distances between the shores, 

the distances between the wind farms, the distances 

between the wind farms and other connection hubs, 

the capacities of all cables, the market conditions in 

every country, the price differences and price difference 

profiles between the countries, as well as the 

other interconnectors and integrated solutions, either 

existing or planned. The model provides clear guidelines 

for such parameter considerations and thus for 

the design to be chosen. 

Case 1 Case 2 Case 3,4,5,6 

Case 7 


4.4.3 The Cobra cable case study 

To validate the results, the Cobra cable interconnection 

between the Netherlands and Denmark has been 

analysed as an additional case study. This is a very 

interesting case due to the following aspects: 

• Tennet and Energinet.dk have received funds from 

the European Commission under the European 

Economic Recovery Programme to allow the teeingin 

of future wind farms along the route. 

• The investment decision will be taken shortly (in 2012). 

• Due to its timing and location close to three different 

countries, it is generally seen as one of the 

first cornerstones of a future European Offshore 

Supergrid. 

The Cobra cable was originally planned as a 700 MW 

direct interconnector between the Netherlands and 

TAblE 4.5: cAlcUlATEd cASES FOR ThE EXTRA cASE STUdY: cObRA cAblE 


Denmark to be built and operated by the Dutch and 

Danish Transmission System Operators (TSOs), 

Tennet and Energinet.dk respectively. Currently investigations 

are ongoing whether it makes sense to 

connect German wind farms along the route as well. 

The Cobra cable route passes close to several large 

German offshore wind farms, located far from shore 

and thus facing high connection costs. The Dutch and 

Danish wind farms located close to the Cobra cable 

route are closer to the shore and hence may not be as 

cost effective for linking to the cable against a direct 

connection design. 

There are a variety of possible configurations for integration 

of the German wind farm (respectively wind 

farm hubs). A distinction can be made between: 

• A tee-in solution in which the German wind farm 

(hub) is not connected individually to Germany, and 

case Wind Farm (hub) 

Wind Farm connection 

Wind Farm connection 

in focus 

to cobra cable 

to Germany 

1 None – Hub Base Case 2030 Not applicable Not applicable 

2 Butendiek (400 MW) Full WF capacity (B) 0 MW 

3 HDE002 Cluster 1,000 MW Full WF capacity (H) 

4 

(1,300 MW) 

Nordsee Ost phase 1, 

500 MW Full WF capacity (H) 

5 Hochsee Testfeld Helgoland, 500 MW Full WF capacity (H) – 500 MW 

6 Meerwind phase 1, 250 MW Full WF capacity (H) – 250 MW 

7 Amrumbank West Full WF capacity (H) O MW 

FIGURE 4.20: cOMPARISON cOST-bENEFIT ObTAINEd bY INTERcONNEcTING A GERMAN WINd FARM INTO ThE cObRA cAblE 

(PARTlY OR cOMPlETElY) (NEGATIvE = bENEFIcIAl) 

Cost bene�t (€m) 

(negative = bene�cial) 

0 

-50 

-100 

-150 

-200 

-250 

-300 

-350 

-400 

-250 

Case 2 

-96 

Case 3 

-53 

Case 4 

-167 

Case 5 

-82 

Case 6 

-341 

Case 7 

55

esults 

• A three-leg interconnector where the teed-in wind 

farm (hub) is also connected to Germany. This 

design thus links the Netherlands, Denmark and 

Germany allowing multilateral electricity trade. 


Seven different cases are investigated (Table 4.5 and 

Figure 4.19). The objective is to evaluate: 

• Whether the inclusion of a wind farm on the cable 

is beneficial. For this assessment the teeing-in 

of two different wind farm/hubs is analysed separately: 

Butendiek (400 MW) and HDE002 Cluster 

(1,300 MW). (Case 2 and Case 7), 

• Whether developing a link between the Cobra cable 

and a large shore-connected German wind farm 

cluster (HDE002) is beneficial – the so called threeleg 

configuration (Case 3 and Case 4), 

• Whether the connection capacity of the German 

wind farm cluster HDE002 to shore can be reduced 

in capacity (different sizes investigated) by introducing 

a link to the Cobra cable (Case 5 and Case 6). 

Costs and benefits are compared against the Hub 

Base Case 2030 (Case 1). 

Costs and benefits 

Figure 4.20 shows the results of the cost-benefit 

analysis for the Cobra cable case study. It is possible 

to conclude that the inclusion of a wind farm on 

the Cobra cable is beneficial for all cases (see next 

section). 

• Three-leg interconnector is beneficial. 

The results show that for higher connection capacities 

from the wind farm to the Cobra cable (i.e. the 

more German wind that can be sent to either the 

Netherlands or Denmark), the benefits are higher. 

• Connecting the wind farms only to the Cobra cable 

and not to Germany creates the most beneficial 

cases - even if the capacity of the wind farm is higher 

than the capacity of the Cobra cable. 

• Teeing-in the large wind farm cluster (almost double 

the capacity of the Cobra Cable) yields the biggest 

net benefit. This proves the conclusion on splitting 

the wind farm to-shore connection and connecting 

it to two separate countries, as discussed in 

Section 4.4.1. 

Discussion 

It may seem surprising at first sight that the tee-in 

design is beneficial for all cases. However, considering 

the overall power system configuration, the explanation 

is rather simple. At times of high wind generation 

in Northern Europe, German electricity prices are lower 

than Danish and Dutch electricity prices. This is due to 

the simple market logic that wind energy is generated 

at almost zero marginal costs and therefore lowers 

spot market prices in Germany significantly 24 . 

Due to these price gradients it is beneficial to export 

electricity from Northern Germany. This of course also 

holds for offshore wind energy that can be transmitted 

to neighbouring countries instead of being fed 

into the mainland grid where low electricity prices give 

low returns. This is in particular the case for northern 

Germany: with massive onshore and offshore wind 

power capacity, there will often be excess wind power 

generation during periods of high wind which lowers 

the spot market prices. The wind power is therefore 

transmitted to the Netherlands or to Denmark where 

higher prices promise higher returns. According to the 

model, this is more beneficial than an interconnection 

between the latter countries 25 . 

This conclusion is supported by the case-independent 

model where it was shown that increasing the connection 

capacity to the country which usually has the 

highest prices is the most beneficial option (section 

4.4.1). Following this reasoning and taking into account 

the results from the case-independent model, 

the most promising grid design solution is to connect 

some of the German wind farms to two or three neighbouring 

countries. With a relatively modest extra cost 

24 The model of course allows trade exchange across national borders similar to today’s coupled electricity market. However interconnection 

capacity is limited and therefore high wind power generation in Germany first of all lowers the electricity prices within the 

German boundaries. 

25 In Germany there is a strong need for onshore reinforcement between Northern Germany and the Southern part. In the model, 

planned onshore reinforcement is already taken into account and the offshore wind farms are connected deep inland. However, 

the massive wind energy deployment in the North still leads to excess energy and low prices. In case the onshore bottlenecks are 

solved, this might have an impact on the benefits of the tee-in solution. 


compared to the individual connection to Germany 

only, a two- or three-leg interconnector is created 

which can be used, amongst other things, to relieve 

the stress on the German market. 

Apart from techno-economic considerations, an integrated 

solution is heavily dependent on the political 

and regulatory decisions. For example, it is of course 

not possible without a solution for the incompatibility 

of support systems (see further in Chapter 6). 

4.4.4 Conclusion on 

integrated design 

Sections 4.3 and 4.4 have elaborated the results of 

the cost-benefit analysis on integrated design options. 

They have been evaluated by an extensive case study 

analysis with the previously described combination 

of an infrastructure model, a power market and flow 

model. The results were strongly case-sensitive and it 

was therefore impossible to draw general conclusions 

or develop universal guidelines. Therefore a case-independent 

model was developed in order to carry out 

various sensitivity analyses to develop the essential 

concrete grid design guidelines. 

The analysis focused on two major design problems that 

form the basis of offshore grid concepts: the teeing-in 

of wind farms into interconnectors, and the interconnection 

of two wind farm hubs. The results, insights 

and conclusions are also valid for more complex design 

problems with nodes connecting more than two lines. 

For wind farms far from shore, teeing them into an 

interconnector can be an interesting option. This is 

especially true in two cases: 

• The integration of small wind farms rather far from 

shore but close to an interconnector (e.g. offshore 

wind at oil & gas platforms) that put only small electricity 

trade constraints on the interconnector, 

• The connection of big wind farms or wind farm hubs 

to two countries. When connecting them to both 

countries with the same total connection cable capacity 

as in a conventional solution, the additional 

infrastructure costs are limited and a large interconnector 

is created at the same time. 


Hub-to-hub interconnections have shown to be interesting 

under certain circumstances. In general the 

projects should be far from shore but close to each 

other. If the hub-to-hub interconnector is small, it will 

help to send the electricity from both wind farms to 

the highest price area. Bigger interconnectors are 

interesting when the price difference between the 

countries is high. 

In both tee-in solutions and hub-to-hub solutions, oversizing 

one leg of the system and undersizing the other 

may benefit the design if the price difference profile is 

not balanced. Depending on the local parameters and 

the long term price expectations, an optimal solution 

can be calculated. 

The case-independent model, based on which these 

overall conclusions were developed, provides concrete 

numbers for pre-feasibility checks on the design 

for specific cases. This allows quick design assessments 

and avoids lengthy iterative processes. The 

case-independent model results are directly fed into 

the overall grid design where these guidelines help to 

guide the direct grid development. The suggestions for 

the overall grid design were verified by concrete model 

calculations. 

For completeness, it should be mentioned that economics 

are not the only basis for a decision to develop 

an integrated solution. Other important factors are 

e.g. the timing of each part of the project, the fact that 

an integrated solution can increase the redundancy, 

the ownership structure of the projects, etc. 

The results have been complemented and validated 

with an extra case study, the Cobra cable. This analysis 

has confirmed the conclusion on the connection 

of big wind farms to two countries, as discussed in 

section 4.4.3. Due to high wind expectations, future 

German spot market prices are expected to be low. 

This enforces the effect of the two-country-connection. 

The detailed results of the case-independent model 

are shown in Annex D.II on www.offshoregrid.eu. The 

results can be used as general guidelines for project 

developers, policy makers, regulators and TSOs to 

assess whether the discussed design solutions (hubto-hub, 

tee-in, split wind farm connection) could be 

beneficial for the projects planned. 

57

esults 

4.5 Overall grid design 

4.5.1 Approach 

The development of the offshore grid is going to be 

driven by the need to bring offshore wind energy online 

and by the benefits from trading electricity between 

countries. This involves on the one hand the connection 

of the wind energy to where it is most needed, and 

on the other hand the linking of high generation cost 

areas to low generation cost areas. There are numerous 

methodologies that could be applied to achieving 

these objectives. In this section, the OffshoreGrid 

consortium demonstrates the effectiveness of two 

different methodologies to design a beneficial costeffective 

overall offshore grid. 

Both methodologies use as a starting point the 

OffshoreGrid Hub Base Case scenario 2030. This 

includes the direct or hub connections to each of 

offshore wind farm in the North and Baltic Seas (as 

defined in section 4.2), and the offshore reinforcements 

identified in the ENTSO-E Ten Year Network 

Development Plan (TYNDP) [56]. Based on this, the 

following design development strategies are applied: 

• The direct design Methodology mimics the current 

evolution as it is envisaged today: First, direct interconnectors 

are built to promote unconstrained 

trade as average price difference levels are high. 

Once additional direct interconnectors become 

non-beneficial, tee-in, hub-to-hub and meshed grid 

concepts are added to arrive at an overall grid 

design. 

• The Split design Methodology considers an approach 

that starts with a conclusion from the 

case-independent model (see section 4.4.4). The 

idea is that interconnections are built by splitting 

the connection of some of the larger offshore wind 

farms between countries. Thereby a path for constrained 

trade is established. These offshore wind 

farm nodes are then further interconnected to establish 

an overall ‘meshed’ design where beneficial. 

A large number of iterations and sensitivity analyses 

were carried out for each of the two methodologies 26 

in order to prove that each added infrastructure module 

was beneficial. Each of the methodologies is 

explained in detail in the following two chapters. The 

results are compared in section 4.5.4 to see which 

kind of development is most efficient in terms of reducing 

European total system generation costs. 

TAblE 4.6: ENERGY PRIcE dIFFERENcES (IN €/MWh) AS dETERMINEd bY POWER MARkET MOdEl FOR ThE hUb bASE cASE 

ScENARIO 2030 

BE De DK ee Fi Fr GB Ie lT lV Nl NO Pl se 

BE 4.6 9.7 6.4 23.7 10.1 9.4 8.2 6.9 6.4 7 17.5 6 25.9 

De 4.6 7.5 5.4 22.1 9.5 8.8 8.8 5.4 5.4 5.3 15.7 4.4 24.0 

DK 9.7 7.5 6.2 16.2 7.6 8.9 11.4 5.8 6.2 6.3 10.1 6.9 17.0 

ee 6.4 5.4 6.2 18.8 8.5 10.0 10.4 1.2 0.0 8.1 13.4 3.7 21.1 

Fi 23.7 22.1 16.2 18.8 16.5 20.3 23.4 19.0 18.8 20.7 9.9 20.9 7.3 

Fr 10.1 9.5 7.6 8.5 16.5 8.9 11.3 8.5 8.5 8.3 10.6 9.6 17.2 

GB 9.4 8.8 8.9 10.0 20.3 8.9 6.1 9.9 10.0 6.5 15.0 10.0 21.2 

Ie 8.2 8.8 11.4 10.4 23.4 11.3 6.1 10.6 10.4 8.6 10.1 10.2 24.8 

lT 6.9 5.4 5.8 1.2 19.0 8.5 9.9 10.6 1.2 7.8 13.4 2.8 20.5 

lV 6.4 5.4 6.2 0.0 18.8 8.5 10.0 10.4 1.2 8.1 13.4 3.7 21.1 

Nl 7.0 5.3 6.3 8.1 20.7 8.3 6.5 8.6 7.8 8.1 14.7 7.2 21.2 

NO 17.5 15.7 10.1 13.4 9.9 10.6 15.0 18.1 13.4 13.4 14.7 14.8 8.8 

Pl 6.0 4.4 6.9 3.7 20.9 9.6 10.0 10.2 2.8 3.7 7.2 14.8 22.1 

se 25.9 24.0 17.0 21.1 7.3 17.2 21.2 24.8 20.5 21.1 21.2 8.9 22.1 

26 Please note that the two methodologies only differ in the first step. The Direct methodology focuses first on direct interconnectors, 

while the Split methodology focuses first on split wind farm connections. 


4.5.2 The direct design methodology 

The Direct Design Methodology is built on three steps: 

Step 1) The construction of direct interconnectors 

taking the large price difference between 

countries as guidance. 

Step 2) Beneficial tee-in solutions or the interconnection 

of countries via hub-to-hub connections 

were identified.(Step 2 was only started when 

step 1 could not identify any more beneficial 

direct interconnectors) 

Step 3) Beneficial meshed connections were identified. 

(Step 3 was only started when neither 

step 1 nor step 2 could identify beneficial 

connection solutions) 

Each step is explained in more detail below. 

Step1: Direct design methodology – 

direct interconnectors 

To assess the economic viability of direct interconnectors 

within Northern Europe a justification formula was 

developed to test the profitability of interconnectors. 

This worked as follows: 

• The power market model was used to initially create 

a reference case of energy price differences 

between the countries around the North and Baltic 

Seas, 

• The price differences were used to determine the 

potential interconnector revenue. The capital cost 

of each interconnector is calculated, 

• Costs and revenues are compared, and the interconnectors 

are ranked according to profitability, 

27 Ten proved to be a sufficiently large number. If it had shown that there would have been more than ten beneficial links, the number 

of selected links to be tested would have been increased. Furthermore please note that, as explained below, an iterative process 

was carried out and step 1 of the Direct Design was repeated in order not to miss any beneficial direct interconnectors. 

28 Note that this methodology did identify that multiple 1,000 MW interconnectors between the same countries could be beneficial, 

and hence in order to separately identify the net benefit, each interconnector has been modelled discretely at 1,000 MW. In reality 

where a net benefit is identified for multiple interconnectors between the same countries, a more cost effective design such as a 

single 2,000 MW bipole may be implemented. 

29 Either based on long term supplier/interconnector capacity contracts (60%) or on short term supplier/interconnector capacity 

contracts (100%). The interconnector utilisation figure was derived from the average utilisation of the England France (2,000 MW), 

Moyle (Scotland – Northern Ireland, 500 MW) and NorNed (700 MW) interconnectors using data downloaded from the ENTSO-E 

website from 2008 to 2010. 


• The ten most promising links are selected and 

studied in detail in the power market model 27 . 

The starting point for all calculations is the Hub 

Base Case scenario 2030. The price differences for 

this case are shown in Table 4.6. Based on these, 

the potential revenue for interconnectors between all 

countries which can be connected geographically was 

calculated using the following assumptions: 

• 25 year payback period, 6% discount rate 

• Minimum interconnector utilisation of 63.7% 

• 1,000 MW building blocks for each interconnector 28 

• Interconnector receiving revenue derived from 

either 60% or 100% of the price differences multiplied 

by the expected utilisation (depending on the 

type of contracts) 29 . 

Some of the ten interconnectors identified were between 

countries that also shared a land border. Adding 

links between adjacent countries via an offshore grid 

is unlikely to be the most economically efficient solution 

and including such links in the model may affect 

the overall effectiveness of the offshore grid design. 

Hence, despite the remit of this project excluding reinforcements 

to the onshore network, it was reasonable 

to add onshore AC 1,000 MW capacity reinforcements 

into the power market model where the price 

differentials indi cated a need case between adjacent 

countries in order to make the evaluation of an offshore 

grid design as realistic as possible. 

Following the identification using the above described 

process, the power market model was run with each 

interconnector added in turn to produce the total electricity 

generation cost for the European system. The 

direct interconnectors were beneficial when the total 

generation cost was reduced by more than the capital 

cost of the assets over their lifetime. The direct inter- 

59

esults 

connectors that were beneficial were retained and any 

that were not beneficial were removed from the model. 

Besides reducing the total generation costs, adding 

interconnectors also reduces the price differences between 

countries. Accordingly, the building or omitting 

of direct interconnectors has an immediate impact 

on the price levels and the profitability of the remaining 

proposed interconnectors. To come around this, 

an iterative process was performed and step 1 was 

repeated. Within this process the updated price differences 

were used to identify more interconnectors to 

study in the power market model until the price differences 

were lowered sufficiently so that adding further 

direct interconnectors produced no net benefit. The 

beneficial direct interconnectors selected as a starting 

point for step 2 of the Direct Design Methodology 

are shown in the map in Figure 4.21. 

The development of the price level differences that go 

along with the different offshore grid design steps are 

given in detail in Annex D.III on www.offshoregrid.eu. 

Step 2: Direct design methodology – 

hub-to-hub and tee-in connections 

(integrated design) 

The most promising cases assessed for either hubto-hub 

connection or wind farm tee-in connection 

possibilities, are those direct interconnectors that 

FIGURE 4.21: dIREcT dESIGN METhOdOlOGY – STEP 1: MAP OF ThE SElEcTEd dIREcT INTERcONNEcTORS 



























were rejected as being not beneficial in the previous 

stage. The reasoning behind this is that the high price 

differential still indicates that there could be benefit in 

linking the two countries concerned (for details on the 

price differentials after step 1 refer to Annex D.III.). 

Integrated solutions provide trade opportunities at a 

lower capital cost, even though this trade is not always 

unconstrained as the lines are sometimes loaded with 

offshore wind energy. Thus, the reduced capital costs 

may make a tee-in or hub-to-hub connection beneficial 

where a direct interconnection was not. 

Once the potential tee-in and hub-to-hub connections 

to be assessed have been chosen, the number of 

cases to be studied was further reduced by comparing 

the proposed cases with the conclusions of the 

case-independent model described in section 4.4. As 

discussed, the case-independent model is useful as 

a guidance to quickly evaluate whether a certain case 

needs further investigation or not. Cases where the 

case-independent model clearly showed that there is 

no benefit in going for an integrated solution have thus 

not been investigated further 30 . 

The promising cases were ranked according to the net 

benefit of the corresponding direct interconnectors 

(the non-beneficial ones from the previous phase), 

with the most beneficial being assessed first. The 

FIGURE 4.22: dIREcT OFFShORE GRId dESIGN - STEP2: MAP OF ThE SElEcTEd hUb-TO-hUb cONNEcTIONS 


























30 Cases where the case-independent model indicated that the benefit is positive have thus been further analysed with the infrastructure 

cost model and the power market model. As the case-independent model only gives a guidance to be backed up with more 

detailed case-specific analysis, the cases with a marginal or only slightly negative benefit have also been investigated. 


61

esults 

connections were tested in multiple iterations similar 

to the process for the direct interconnectors in step 1. 

The hub-to-hub connections that demonstrated a 

positive net benefit were retained for each of the next 

phases. 

Step 3: direct design methodology – 

mesh design 

The price differentials between each country that were 

still remaining after step 2 were analysed (cp. details 

on price differentials in Annex D.III.). The countries 

with high price differentials were earmarked as potential 

connection points for an offshore mesh. These 

potential connection points were further refined by ignoring 

any price differentials between countries that 

were impractical and uneconomic to interconnect via 

offshore links such as Belgium and Finland, or Norway 

and Latvia. 

What remained were consistently high price differentials 

between Norway and to a lesser extent Sweden 

and the northern European countries of Germany, 

the Netherlands, Belgium, France, and Great Britain. 

Because additional direct interconnections and in 

some cases hub-to-hub connections between these 

various countries had not proven to be beneficial over 

those established in the previous step, these price differentials 

indicated that variations of a mesh design 

that linked offshore hubs in these countries could prove 

beneficial. Various combinations of links between some 

of the offshore hubs in these countries were analysed. 

FIGURE 4.23: dIREcT OFFShORE GRId dESIGN - STEP 3: MAP OF ThE SElEcTEd MESh IN ThE NORTh SEA 



























To that extent, a 1,000 MW ‘spine’ was established between 

the Idunn hub off Norway, the Dogger Bank hub 

off the UK and the IJmuiden hub off the Netherlands to 

Belgium 31 . Sensitivities were then performed on this 

initial mesh around 32 : 

• the effectiveness of each of the links within the 

‘spine’, 

• adding additional 1,000 MW offshore links to 

Belgium and Sweden from the IJmuiden hub and 

Idunn hub respectively, 

• adding additional 1,000 MW offshore links to Belgium 

and Sweden from the Dutch and Norwegian onshore 

networks mesh connection points respectively, 

• uprating the individual mesh links to 2,000 MW, 

• removal of the ‘redundant’ hub-to-hub link between 

Idunn and IJmuiden from the base model. 

31 As can be seen from Figure 4.23, some parts of this ‘spine’ already existed in the model. As a result of the hub-to-hub analysis, 

the Dogger Bank hub was already connected to the Gaia hub in Germany, and the Idunn hub was already connected directly to 

the IJmuiden hub. Belgium, France, and Sweden were already connected to the Netherlands and Norway respectively via onshore 

reinforcements in the base model. 

32 Unlike for the direct interconnections and the hub to hub connections the possible variations in mesh topology were not exhaustively 

modelled although several sensitivities assessing the effect of changes in capacities, connection points and removal of links around 

the core initial mesh and alternative mesh designs were analysed to arrive at the design presented here. (Further details of these 

sensitivity studies are represented in Annex D.III.I to this report). 

Whilst other alternative mesh designs are certainly possible and may even be more beneficial, it was felt that the proposed design 

demonstrated the benefit of a meshed offshore grid and was already sufficiently complex to make implementation by 2030 ambitious. 


Figure 4.23 shows the overall final grid design after 

step 3 of the Direct Design Methodology for the North 

and Baltic Seas. 

Results – direct design 

Figure 4.24 shows the infrastructure costs (cumulatively) 

and the total system generation costs, and Figure 4.25 

shows the net benefit of the overall Direct Design. 

As can be seen from Figure 4.24, the cumulative investment 

cost curve (blue bars) for the Direct Design 

is reasonably linear for the direct interconnectors. This 

reflects the discrete investment required in converters 

and cable for every investment. The few larger steps 

for Sweden-Latvia and Ireland-France reflect the greater 

amounts of subsea cable required for longer interconnections. 

The investment cost curve begins to plateau 

for the hub-to-hub cases implemented, as these require 

only an investment in extra subsea cable and utilise the 

FIGURE 4.24: dIREcT dESIGN - cUMUlATIvE cAPEX INvESTMENT cOSTS (blUE, lEFT) ANd SYSTEM GENERATION cOSTS (REd, RIGhT) [€ bN] 

Cumulative investment 

cost (blue) (€bn) 

8 

7 

6 

5 

4 

3 

2 

1 

0 

Base case 

SE-DE 

FI-EE 

SE-PL 

SE-DK 

SE-LV 

GB-FR 

SE-DE 

Cumulative investment costs 

GB-BE 

Direct interconnections 

Hub-to-hub and Tee-in Mesh 

Omitted as not bene�cial. Shown to compare with direct design 

GB-FR 

SE-PL 

SE-DK 

IE-FR 

IE-GB 

GB-BE 

NO-NL 

Annual system generation costs 

SE-DK 

System generation 

cost (red) (€bn) 

NL-GB 

GB-DE 

Mesh 

100,5 

100,0 

99,5 

99,0 

98,5 

98,0 

63

esults 

existing HVDC converters at each hub. Thus, the hub-tohub 

investment costs are relatively low. 

Along with these infrastructure investments the electricity 

generation costs (in Figure 4.24, red curve) in 

the European power system decrease. The annual 

generation cost curve shows - similar to the cumulative 

investment curve - linear reductions for the direct 

interconnections, a flattening of the curve for the hub 

to hub cases and a further sharp reduction when the 

mesh is introduced. The entire Direct Design reduces 

the system costs by €1.3 bn per annum (=€20.5 bn 

over 25 years) for a total investment cost of €7.4 bn. 

How large the benefit per investment is, is best shown 

in Figure 4.25. Here the net benefits (red bar) and the 

benefit-to-CAPEX ratio (blue marker) of each project are 

given for a life time of 25 years. In particular the meshed 

network exhibits a large benefit-to-CAPEX ratio. As all investments 

are beneficial and produce net benefits, the 

benefit-to-CAPEX ratio is always bigger than 100%. Some 

investments produce benefits of up to 7 times the initial 

investment (benefit-to-CAPEX ratio of 700%). 

The final step of the meshed grid design creating a 

meshed network between Norway and Great Britain, 

Germany, the Netherlands and Belgium generates 

significant net benefits over 25 years (€2.3 bn) for a 

FIGURE 4.25: GRId dESIGN: NET bENEFIT (REd, lEFT) ANd bENEFIT-TO-cAPEX RATIO (blUE, RIGhT) 

[€bN]. (PlEASE NOTE ThE dIFFERENcE bETWEEN NET bENEFIT ANd bENEFIT.) 

Net bene�t 

(red) (€bn) 

25 

20 

15 

10 

5 

0 

Base case 

SE-DE 

FI-EE 

SE-PL 

SE-DK 

SE-LV 


GB-FR 

SE-DE 

Net bene�ts (across lifetime) 

GB-BE 

GB-FR 

SE-PL 

relatively modest investment cost (€670 m) reaching 

a benefit-to-CAPEX ratio of almost 400%. Again, this 

is because the additional investment is only in extra 

cabling, as the existing hub converters are utilised. 

4.5.3 The split design methodology 

The case independent model (section 4.4) clearly 

identified that splitting the connection of wind farms 

(or hubs) to two separate shores can be a very cost 

effective and beneficial solution: the wind farm is connected 

to shore and at the same time a relatively cheap 

interconnector can be built. It was further identified that 

the splitting solution is most beneficial for large wind 

farms or hubs which are far from the onshore connection 

point but are relatively close to another country, 

and when the price difference (see Annex D.III. for price 

level differences) between the two countries is high 

enough to make up for the additional infrastructure 

costs. As these findings presented a very promising 

grid design solution, the split wind farm concept was 

taken into account for the second methodology. Similar 

to the Direct Design methodology, the starting point is 

the Hub Base Case scenario 2030 with hub-connected 

wind farms and again the three-step methodology 

was applied. However, this time also split wind farm 

connections were considered in the first step. Even 

though the second and third steps for the Split Design 

Bene�t-to-CAPEX 

ratio (blue) % 


SE-DK 

IE-FR 

Hub-to-hub Mesh 


IE-GB 

GB-BE 

NO-NL 

SE-DK 

Bene�t CAPEX ratio (across lifetime) 

NL-GB 

GB-DE 

Mesh 

800 

700 

600 

500 

400 

300 

200 

100 

0

Methodology remain the same, the changes in the first 

step have of course an impact on the results of step 2 

and step 3: 

Step 1) The methodology is based on step 1 of the 

Direct Design. Split wind farm connections 

were considered where it was possible to 

replace direct interconnectors. Those split 

wind farms that are beneficial to retain were 

identified, along with the direct interconnectors 

where splitting wind farm connections was 

not possible. Thus as a result of step 1 

beneficial direct interconnectors and split 

wind farm connections are obtained. 

Step 2) Beneficial tee-in solutions or the interconnection 

of countries via hub-to-hub connections 

were identified. (Step 2 was only started 


when no further beneficial split wind farm 

connections could replace the direct interconnectors 

of step 1 in the Direct Design). 

Step 3) Beneficial meshed connections were identified. 

(Step 3 was only started when neither 

step 1 nor step 2 could identify beneficial 

connection solutions) 

Each step is explained in more detail below. 

Step 1: Split design methodology – 

split wind farm connections 

To select the wind farms that can be split, a methodology 

based on the aforementioned characteristics 

was developed. In order to compare the results with 

the Direct Design, the beneficial interconnectors (both 

FIGURE 4.26: SPlIT OFFShORE GRId dESIGN - STEP 1: MAP OF ThE SElEcTEd SPlIT WINd FARM cASES 

























65

esults 

direct and integrated) identified as being beneficial 

were mirrored with appropriate split wind farm connections. 

This means that the split wind farm connections 

connect the same countries as the direct interconnectors 

in the Direct Design approach. 

The wind farms or wind farm hubs to be split have 

been selected based on their capacity and on the additional 

cable length to the other country. The wind farm 

(hub) for each comparative link from the Direct Design 

method which came out best, was then modelled as 

a split connection in the power market model to assess 

overall benefit. For those direct interconnectors 

identified in the Direct Design method where no appropriate 

wind farm (hub) for splitting the connection 

could be identified, the original direct interconnector 

was retained in the model. 

FIGURE 4.27: SPlIT OFFShORE GRId dESIGN - STEPS 2 ANd 3: MAP OF ThE MESh dESIGN 











Sensitivity studies were performed initially around 

the capacity of the split connection links. The options 

studied (suggested by the case-independent model) 

were: 

• Each connection link from the offshore wind farm 

carries half of the installed capacity of the wind 

farm (50% option). 

• The connection link to the country with the lower 

generation price is rated half of the installed capacity 

of the wind farm. The connection link to the 

country with the higher generation price is rated 

to carry the full installed capacity of the wind farm 

(50/100% option). 

The result of the sensitivity analysis showed that the 

50% option was already beneficial, but the 50/100% 
















option was better. Following these results, all the split 

connections in the model were designed according to 

the 50/100% option. 

Step 2: Split design methodology – 

hub- to-hub and tee-in connections 

Step 2 tested whether there are any beneficial hubto-hub 

or tee-in connections. The connection of two 

hubs in different countries allows trade across the 

newly established interconnectors via the hubs. Trade 

is of course also possible via a tee-in connection. 

Accordingly the price differentials between the countries 

are used as indicators to identify potentially 

beneficial hub-to-hub or tee-in connections (compare 

Annex D.III.IV.). 

Several potentially beneficial hub-to-hub interconnections 

as identified in the Direct Design were tested 

with the market model. The infrastructure measure 

was regarded as beneficial when the generation costs 

reduction of the power system was higher than the 

infrastructure costs. 

(REd, RIGhT) (€ bN) 

Cumulative investment 

cost (blue) (€bn) 

6 

5 

4 

3 

2 

1 

0 


Cumulative investment costs 

Within step 2 the hub-to-hub cable connecting NL and 

GB was identified to be beneficial. That only one case 

was identified is due to the split wind farm connection 

of step 1 that already boosted the cross-border 

capacity between the countries and further reduced 

the price differences. 

Step 3: Split Design Methodology – 

Mesh Design 

Again sensitivities of mesh design were run in addition 

to the interconnections already identified in steps 

1 and 2 above. The same topology of mesh design 

to the direct case was found to be most beneficial, 

with a ‘spine’ running from the Idunn hub in Norway, 

to the UK Dogger Bank, to the IJmuiden hub off the 

Netherlands 33 and then to Belgium. The mesh also 

includes an interconnector between the Dogger Bank 

and the German Gaia hub. 

The price differentials between the countries developed 

differently in the Split Design compared to the Direct 

Design. Therefore the cable capacities of the mesh 

FIGURE 4.28: SPlIT OFFShORE GRId dESIGN: cUMUlATIvE cAPEX INvESTMENT cOSTS (blUE, lEFT) ANd SYSTEM GENERATION cOSTS 

Base case 

SE-DE 

FI-EE 

SE-PL 

SE-DK 

SE-LV 

GB-FR 

SE-DE 

GB-BE 

GB-FR 

SE-PL 

SE-DK 

IE-FR 

IE-GB 

GB-BE 

NO-NL 

Annual system generation 

cost (red) (€bn) 

Direct interconnections Split interconnections Hub-to-hub and Tee-in Mesh 


SE-DK 

NL-GB 

GB-DE 

Annual system generation costs 

33 As can be seen from Figure 4.23, some parts of this ‘spine’ already existed in the model. As a result of the hub-to-hub analysis, 

the Dogger Bank hub was already connected to the Gaia hub in Germany, and the Idunn hub was already connected directly to 

the IJmuiden hub. Belgium, France, and Sweden were already connected to the Netherlands and Norway respectively via onshore 

reinforcements in the base model. 

Mesh 

100,5 

100,0 

99,5 

99,0 

98,5 

98,0 

67

esults 

configuration were rated differently than in the Direct 

Design in order to achieve the optimal design. Rating 

the Norway to Great Brian to Netherlands sections of the 

mesh at 2,000 MW was found to be most beneficial. 

With the direct and split mesh design having the same 

topology, it allows the benefit-to-CAPEX ratio to be 

compared. 

Results – Split Design 

The investment costs in the split wind farm designs are 

lower than for their direct interconnector counterparts in 

the Direct Design (see Figure 4.28). This is due to the 

fact that the split farm connection represents two-in-one: 

a direct connector and a wind farm-to-shore connection. 

When comparing the system costs in Figure 4.28 

with Figure 4.24, it is also clear that reduction in overall 

system costs is smaller for the Split Design due to the 

higher trade constraints 34 . 

Some of the direct interconnectors that are not beneficial 

in the Direct Design, such as the second Great 

Britain to Belgium link, are now producing positive net 

Net bene�t 

(red) (€bn) 

2,5 

2,0 

1,5 

1,0 

0,5 

0,0 

Net bene�ts (across lifetime) 

benefits (Figure 4.29). This proves that the offshore grid 

design with the split wind farms reduces the system 

costs (and thus the price differences) with smaller steps 

due to the higher trade constraints on the interconnector. 

The higher price differences make the remaining direct 

interconnectors more beneficial. However, this does not 

mean that the split wind farm connections are less effective. 

As is shown below the split wind farm connections 

even generate a higher relative system cost reduction 

when put in relation to the investment costs (benefit-to- 

CAPEX ratio). 

The introduction of a mesh in step 3 also produces significant 

net benefits of €1.8 bn across 25 years for an 

investment of only €1 bn. Note that the mesh is less 

beneficial than in the Direct Design. The reason is that 

the mesh is now built between wind farms that are already 

connected to two countries with the split design 

concept identified in step 1. The split connection already 

leads to an increased utilisation of the cables, so that 

the actual mesh cables between the wind farm hubs are 

constrained more severely. This leads to a lower absolute 

reduction in system costs than in the Direct Design 35 . 

FIGURE 4.29: SPlIT OFFShORE GRId dESIGN:NET bENEFIT (REd, lEFT) ANd bENEFIT-TO-cAPEX RATIO (blUE, RIGhT) (€ bN). 

(PlEASE NOTE ThE dIFFERENcE bETWEEN bENEFITS ANd NET bENEFITS.) 

Base case 

SE-DE 

FI-EE 

SE-PL 

SE-DK 

SE-LV 


GB-FR 

SE-DE 

GB-BE 

GB-FR 

SE-PL 


ratio (blue) (€bn) 


SE-DK 

IE-FR 


IE-GB 

Split interconnections Hub-to-hub and Tee-in Mesh 

GB-BE 

NO-NL 

Direct Design Bene�t CAPEX ratio 

34 Note that in the results the Finland–Estonia, Sweden–Latvia, Great Britain–France, Ireland–France, and Great Britain–Belgium links 

all remain as direct interconnectors. 

35 Step 3 in the Split Design methodology is strongly based on step 3 in the Direct Design methodology for reasons of comparability. 

The specific development of a mesh design for the Split Design will probably yield higher net benefits. 

SE-DK 

NL-GB 

GB-DE 

Mesh 

1600% 

1400% 

1200% 

1000% 

800% 

600% 

400% 

200% 

0%

The overall Split Design reduces the system costs by 

€15.8 bn across 25 years for a total investment cost 

of €5.4 bn. 

4.5.4 Comparison of methodologies 

It should be highlighted that both the Direct Design 

and the Split Design methodology lead to significant 

net benefits. Immediately the question raises which 

of the two leads to the most cost-efficient offshore 

grid design. Such a comparison would be most sound 

on an equal basis: either with equal total cumulative 

costs in order to see which design brings the most 

reduction in system cost, or with equal total system 

cost reduction in order to identify which design has the 

lowest CAPEX. In our case where neither equal system 

reduction costs nor equal CAPEX are given, comparison 

of relative benefits by evaluating the reduction in 

system cost per invested euro is most useful. 

In the following paragraphs, a comparison is made 

based both on relative and absolute terms 36 . However, 

first of all it is instructive to shortly analyse the in- 

36 Please note that the overall cumulative investment costs and the reduction in system generation costs shown in Figure 4.30 to 

Figure 4.34 only consider the investments made for the steps described in paragraphs 4.5.2 and 4.5.3. The total costs of the 

overall grid design are further detailed in section 4.5.5. 

A number of cases does not follow this general rule. 


Split Design Methodology - 

newly installed in each step 

Direct design - 

newly installed in each step 

terconnector capacities that come along with the two 

design approaches. 

Interconnection capacity – comparison for 

the direct and split design approach 

OffshoreGrid starts to develop an overall grid design 

based on the Hub Base Case scenario 2030. This 

scenario includes all existing grid infrastructure and 

adds the connection of all 2030 offshore wind farms 

with individual connections and hub connections 

where beneficial. The existing infrastructure exhibits 

an offshore interconnection transmission capacity 

in Northern Europe of about 8 GW. Furthermore the 

planned interconnectors of the ENTSO-E TYNDP were 

added, which represent further offshore interconnection 

capacity of 8 GW. 

Thus, the overall grid design development within 

OffshoreGrid starts with an offshore interconnection 

capacity of 16 GW. Based on this the overall grid design 

is developed with the Direct and Split Design 

methodologies in three steps as aforementioned. 

FIGURE 4.30: cOMPARISON ThE cAPAcITY OF All EUROPEAN INTERcONNEcTORS TOdAY, WITh ThE ENTSO-E TYNdP 

INTERcONNEcTORS, WITh ThE ThREE STEPS OF ThE dIREcT ANd SPlIT dESING METhOdOlOGY 

Offshore interconnection 

capacity (GW) 

40,000 

35,000 

30,000 

25,000 

20,000 

15,000 

10,000 

5,000 

0 

Existing 

Offshore 

Interconnector 

Capacity 

ENTSO-E 

TYNDP 

Step 1 

Direct or 

Split design 

Step 2 

Hub-to-hub 

and Tee-in 

Step 3 

Mesh 

Split Design - cumulative 

Direct Design - cumulative 

69

esults 

FIGURE 4.31: cOMPARISON OF cAPEX SPENd PER INTERcONNEcTION, FOR ThE dIREcT ANd SPlIT OFFShORE GRId dESIGN 

METhOdOlOGIES (€ bN) 

Costs per 

interconnection (€bn) 

1.2 

1.0 

0.8 

0.6 

0.4 

0.2 

FIGURE 4.32: cOMPARISON OF ANNUAl REdUcTION IN SYSTEM cOSTS PER INTERcONNEcTION, FOR ThE dIREcT ANd SPlIT 

OFFShORE GRId dESIGN METhOdOlOGIES (€ bN) 

Reduction in system 

generation costs per 

interconnection (€bn) 

0.2 

0.2 

0.1 

0.1 

0 

0 

Base case 

Direct Design 

Split Design 

Base case 

Direct Design 

Split Design 

SE-DE 

SE-DE 

FI-EE 

FI-EE 

SE-PL 

SE-PL 

SE-DK 

SE-DK 

SE-LV 


Omitted as not bene�cial 

SE-LV 



GB-FR 

GB-FR 

SE-DE 

SE-DE 

GB-BE 

Split Design Direct Design 

GB-BE 

GB-FR 



GB-FR 

SE-PL 

SE-PL 

SE-DK 

SE-DK 

IE-FR 


IE-FR 


IE-GB 

IE-GB 

GB-BE 

GB-BE 

NO-NL 

NO-NL 

SE-DK 

SE-DK 

NL-GB 

NL-GB 

GB-DE 

GB-DE 

Mesh 

Mesh

FIGURE 4.33: cOMPARISON OF NET bENEFIT ANd bENEFIT-TO-cAPEX RATIO PER INTERcONNEcTOR cAblE FOR ThE dIREcT ANd SPlIT 

OFFShORE GRId dESIGN METhOdOlOGIES (€ bN) 

Net bene�t 

(€bn) 

2,5 

2,0 

1,5 

1,0 

0,5 

0,0 

Base case 

Direct Design 

Split Design 

The increase of the interconnector capacity with 

each step and for each methodology is shown in 

Figure 4.30. In step 1 and step 2 the additional capacity 

is larger for the Direct Design compared to the Split 

Design. This is because split wind farm connections 

were dimensioned with slightly lower capacity to be 

most beneficial. Furthermore only one beneficial hubto-hub 

connection was identified in the Split Design 

in step 2. In step 3 the optimal mesh is dimensioned 

slightly larger for the Split Design and therefore the 

interconnector capacity increase is larger as well. 

The additional grid interconnector capacity that is added 

to the existing European interconnector capacity 

to develop the OffshoreGrid overall designs is 27 GW 

(20 GW excluding the TYNDP interconnectors) for 

the Direct Design Scenario and 24 GW (16 GW when 

excluding the TYNDP interconnectors) for the Split 

Design Scenario. 

37 For the infrastructure costs in Figure 4.30, the Split Design is more expensive for three cases. This is either because the distances 

are too short to cover for the additional equipment (GB-FR), or because a higher capacity is used (second SE-DK, Mesh). 

38 For the reduction in yearly system costs in Figure 4.31, the Split Design reduces the system cost more than the Direct Design in 

four cases. This is either because no wind farm connection is split and the direct interconnector is still used with higher price differences 

because of the constraints in the previous cases (FI-EE, SE-LV), or because the capacity is higher ánd the price differences 

are higher (second SE-DK, Mesh). 

Note that this is a result of the chosen method to replace the direct interconnectors from the Direct Design. If an offshore grid 

would be independently built on split wind connections, the number of possibilities would be higher. 


SE-DE 

FI-EE 

SE-PL 

SE-DK 

SE-LV 

GB-FR 

SE-DE 

GB-BE 

GB-FR 


SE-PL 

SE-DK 

IE-FR 

IE-GB 

GB-BE 

NO-NL 

SE-DK 


ratio 

Direct interconnections Split interconnections Hub-to-hub and Tee-in Mesh 


Case-by-case: relative comparison 

Figure 4.31 and Figure 4.32 show a case-by-case 

comparison between the Direct and Split offshore grid 

design methodologies, for the reduction in total yearly 

system costs respectively for the CAPEX spend. They 

clearly show that the infrastructure costs are generally 

lower for the Split methodology. Accordingly, the 

reduction in system costs is also lower in the Split 

Design as lower additional interconnections capacity 

is installed (also compare Figure 4.30) 37 . 

It is obvious from Figure 4.31 that splitting wind 

farm connections (marked with red boxes) is indeed 

cheaper than building direct interconnectors. In the 

Split Design, 6 direct interconnectors are replaced 

compared to the Direct Design 38 . The average reduction 

of the CAPEX by choosing a split connection over 

a direct interconnector is more than 65% (ranging 

from 40%-84%). At the same time for these split wind 

NL-GB 

GB-DE 

Mesh 

Direct Design Bene�t CAPEX ratio 

Split Design Bene�t CAPEX Ratio 

1,600% 

1,400% 

1,200% 

1,000% 

800% 

600% 

400% 

200% 

0% 

71

esults 

farm connections, the reduction in system cost is only 

about 40% (ranging from 5-74%) smaller on average, 

compared to the direct interconnector (Figure 4.31). 

Figure 4.33 shows a comparison of the net benefit between 

the Direct Design and the Split Design 39 , and 

the benefit per invested euro (benefit-to-CAPEX ratio). 

For the six split wind farm connections, the benefit per 

invested euro is 1.7 times higher than for the mirrored 

direct interconnectors of the Direct Design. The net 

benefit per invested euro CAPEX is on average even 

2.6 times higher for the Split Design, which means 

that each euro is spent 2.6 times more effectively. 

Case-by-case: comparison of absolute 

benefits 

Both methodologies build on step-wise modular grid 

expansion. In each step new interconnection capacity 

is added to the system and the infrastructure 

integrated in each design differs in size and costs. 

Therefore it is difficult to make an absolute comparison 

of the cost-efficiency. The graph in Figure 4.34 

however gives some more insight in the efficiency of 

both design approaches. It shows the system cost reductions 

mapped against the step-wise infrastructure 

investments. 

FIGURE 4.35: cUMUlATIvE NET bENEFIT cOMPARISON [€ bN) 

Cumulative net 

bene�ts (€bn) 

16 

14 

12 

10 

8 

6 

4 

2 

0 

12,74 

280% 

Direct design Split design 

Net bene�t over the lifetime 

FIGURE 4.34: AbSOlUTE cOMPARISON OF dIREcT ANd SPlIT 

OFFShORE GRId dESIGNS 

Annual system 

costs (€bn) 

Often for a similar investment cost, the system cost 

reduction in the Split Design is higher than in the 

Direct Design. As an example, for a CAPEX of €4 bn, 

the Split methodology leads to an extra 9% of system 

cost reduction (=€944 m across 25 years) compared 

to the Direct methodology. Basically only for the cumulative 

investment of about €1.5 bn the Direct Design 

is more effective. 


ratio 

350% 

39 When comparing case-by-case, please note that the price difference development is changing differently for the Direct and Split 

Design as the infrastructures measures are not always the same. Thus, also the benefits of following projects are influenced. 


101 

100 

99 

98 

0 

297% 

9,64 

Bene�t capex ratio (over the life time) 

Direct design 

Split design 

2 4 6 8 

Capital cost (€bn) 

300% 

250% 

200% 

150% 

100% 

50% 

0%

FIGURE 4.36: dc cAblE cIRcUIT ANd Ac cAblE cIRcUIT lENGTh IN ThE dIFFERENT ScENARIOS 

Circuits 

lengths (km) 

50,000 

40,000 

30,000 

20,000 

10,000 

0 


Radial reference 

case 

Reference and base case Overall grid design 

Split Design 

Direct Design 

Hub Base 

Case 2030 

Direct Design 

FIGURE 4.37: NUMbER OF INSTAllEd dc cONvERTERS IN ThE dIFFERENT ScENARIOS 

Converter 

numbers 

400 

350 

300 

250 

200 

150 

100 

50 

0 

Radial reference 

case 

Split Design 

Direct Design 

TYDP 

Hubs 

TYDP Individual Connections 

Hubs 

Split Design 


Hub Base 

Case 2030 

Direct Design 

AC 

Individual Connections 

Split Design 

73

esults 

Overall design comparison 

Figure 4.35 compares the cumulative net benefit 

for the Direct and Split offshore grid designs on an 

absolute and relative basis (benefit-to-CAPEX ratio). 

Although the net-benefit of the Direct Design is larger 

and outweighs the one of the Split Design by €3.1 

bn, this does not mean that the Direct Design is 

more efficient. In fact, this only proves that the Direct 

methodology has gone further in the development: 

more is invested in the trade of energy in order to 

reduce the system cost more. The relative comparison 

is more interesting here. Even though both designs 

are highly beneficial and the difference between them 

is small, the Split Design returns 297% of the initial 

investment as benefits over 25 years, while the Direct 

design only returns only 280% of system benefit per 

invested euro. When evaluating this figure, it should 

be kept in mind that the Split Design is build based 

on mirroring the interconnectors in the Direct Design. 

A complete optimisation starting with split wind farm 

connections might yield higher benefits when the 

same overall investment is done. 

FIGURE 4.38: TOTAl cOSTS FOR ThE OvERAll GRId dESIGN 

Split offshore grid design 

Direct offshore grid design 

4.5.5 Infrastructure investment – 

circuit length and total costs 

The previous paragraphs have analysed the additional 

costs for adding the Direct Design or Split Design to 

the Hub Base Case scenario. To complete the analysis, 

this paragraph gives an overview of the total costs 

of an offshore grid in Northern Europe. Furthermore 

it is instructive to have a look at the overall circuit 

length and the number of DC inverters that are implemented 

in each design. The following scenarios will 

be compared: 

• Radial reference scenario, where all 2030 offshore 

wind farms are connected with individual connections. 

The ENTSO-E TYNDP direct interconnectors 

are included. In this scenario no hub connections 

are realised. 

• Hub Base Case scenario, where the 2030 offshore 

wind farms are connected via hubs where beneficial. 

The ENTSO-E TYNDP direct interconnectors 

are also included. As mentioned before, this is the 

base case used for most comparisons in the whole 

document. 

• Direct Design scenario: An overall grid design built 

on the Hub Base Case scenario as described in 

chapter 4.5.2. 

Reference scenario 

bene�ts due to reduced 


cost (€bn) 

electricity generation costs 

over 25 years (€bn) 

100 


100 

90 

80 

92 

83 

78 

86 

84 

90 

80 

70 

69 

70 

60 

60 

50 

50 

40 

40 

30 

30 

20 

€ 21 

€ 16 

20 

10 

10 

0 

Radial Base case Hub Base case 

Direct Design 

Split Design 

0 

ENTSO_E interconnectors 

Hub wind farm connections 

Individual connections 

Annual generation bene�ts 


• Split Design scenario: An overall grid design built on 

the hub case scenario as described in chapter 4.5.3. 

Cable circuit length and number of installed 

DC converters 

The installed AC and DC cable circuit length for each 

scenario is displayed in Figure 4.36. The “worst 

case” Radial reference scenario, in which all offshore 

wind farms are connected individually, exhibits with 

42,000 km the largest overall circuit length to be installed. 

The circuit length is dramatically reduced to 

28,000 km for the Hub Base Case scenario 2030 in 

which the offshore wind farms are connected to hubs. 

The Hub Base Case scenario served as the starting 

point for the overall grid design development. The additional 

circuit length to develop these was 3,000 km for 

the Split Design and 3,800 km for the Direct Design. 

The overall circuit length for the overall grid design is 

31,000 km for the Split Design and 32,000 km for the 

Direct Design, 10,000 km of which are AC cables in 

each of the cases. Note that these figures show the 

circuit length. As AC circuits use 1 x 3 core AC cable 

and DC circuits use 2 x 1 core DC cables, the total 

cable length is higher. 

TAblE 4.7: UTIlISATION OF WINd FARM cAblES 

connection 

Hub Base Case (Step 

0) 

Direct Design (Step 

2, before mesh) 

Direct Design (Step 

3) 

Split Design (Step 2, 

before mesh) 

Split Design (Step 3) 

40 For Germany onshore connection points have been chosen far inland. This approach is based on the detailed national study dena- 

Netzstudie I (dena grid study I). The connection points far inland increase the overall connection costs to certain extend. 


Dogc-GB 

DogE-GB 

NorfB-GB 

The DC converter numbers for each scenario exhibit 

the same characteristics for the different scenarios. 

In the Radial reference scenario almost 300 DC inverters 

are installed, but the the number is largely reduced 

to 206 for the Hub Base Case. 

In the final Direct Design the overall installed converter 

number is 235. In the Split Design 226 converters 

are used. 

Overall costs of the different scenarios 

Finally, Figure 4.38 summarises the overall costs and 

lists the overall electricity generation costs. It is important 

to highlight that the costs should always be 

compared taking into account the system benefits of 

reduced electricity generation costs due to larger trade 

capacities via the additional infrastructure. Please 

note that the infrastructure costs have only been assessed 

up to the onshore connection point. 40 Costs 

for onshore grid reinforcement needs are not included. 

• Costs and benefits of the Radial reference scenario 

It is clearly most expensive to connect all offshore 

wind farms individually without considering hubs 

connections. Including the ENTSO-E TYDNP interconnectors, 

the investment costs until 2030 would 

amount to €92 bn. 

Ljm_5-NL 

Cap MW 1,800 1,800 1,800 1,800 1,350 990 900 1,710 

Util % 53.8 53.6 53.0 53.4 53.3 56.5 57.1 55.0 

Cap MW 1,800 1,800 1,800 1,800 1,350 990 900 1,710 

Util % 53.8 71.3 68.4 67.7 68.4 59.0 57.1 65.2 

Cap MW 1,800 1,800 1,800 2,800 1,350 990 900 1,710 

Util % 53.8 81.8 59.7 77.1 53.3 74.8 57.1 62.8 

Cap MW 1,800 1,800 1,800 1,800 1,350 500 500 1,710 

Util % 53.8 53.6 59.3 53.4 53.3 85.1 85.2 55.0 

Cap MW 1,800 1,800 1,800 2,800 1,350 2,010 500 1,710 

Util % 78.3 79.1 55.8 73.0 53.3 79.7 81.5 62.8 

Ljm_2-NL 

idunn-NO 

Ægir-NO 

Gaia-DE 

75

esults 

• Costs and benefits of the Hub Base Case scenario 

2030 

The costs for the offshore wind farm connections 

are significantly reduced in the Hub Base Case scenario. 

As a large number of wind farms is connected 

with cost efficient hub design concepts, the overall 

infrastructure costs are decreased by €14 bn to 

€78 bn (incl. TYNDP interconnectors). However the 

hub design connections do not build new transmission 

corridors between countries, therefore the 

annual power system generation costs remain at 

the high level and no generation costs benefits are 

produced. 

• Costs and Benefits of the Direct Design scenario 

and the Split design scenario 

The direct and Split Designs are built on the Hub 

Base Case scenario 2030. Additional grid infrastructure 

is added: direct interconnections, 

hub-to-hub interconnections, tee-in interconnections 

and meshed grid designs. As additional 

infrastructure is added in both cases the costs are 

increased compared to the Hub Base Case scenario. 

The overall costs of the Direct Design offshore 

grid amount to €86 bn. The Split Design offshore 

grid is €2 bn less expensive and costs €84 bn in 

total. At the same time the annual system generation 

costs are largely decreased as both designs 

add new electricity trading capacity to the system. 

The annual benefits of €1.02 bn (Split Design) and 

€1.3 bn (Direct Design) amount to a net present 

value benefit of €16 bn (Split Design) and €21 bn 

(Direct Design) across a lifetime of 25 years. 

• The additional infrastructure costs to develop the 

Direct or Split Design on top of the Hub Base Case 

scenario 2030 are relatively low. They represent 

only 7% (Split Design) to 9% (Direct Design) of the 

Hub Base Case wind farm connections and the 

ENTSO-E TYNDP interconnectors. At the same time 

they generate large benefits of about three times 

the investments. 

The enormous investments into offshore grid infrastructure 

have to be put into relation to the offshore 

wind energy produced. The offshore wind farms considered 

in OffshoreGrid produce about 530 TWh annually 

which is about the annual consumption of Germany. 

Across 25 years this amounts to 13,300 TWh. Based 

on average spot market prices of €50/MWh, the value 

FIGURE 4.39: chANGE OF PROdUcTION PER TEchNOlOGY IN ENERGY MIX bY AddING ThE OvERAll OFFShORE GRId dESIGN 

(FOR ThE dIREcT dESIGN ANd ThE SPlIT dESIGN) [chANGE IN GWh/YEAR) 

Change in energy mix 

by adding the overall 

offshore grid design 

(GWh/year) 

60,000 

50,000 

40,000 

30,000 

20,000 

10,000 

0 

-10,000 

-20,000 

-30,000 

Hydro 

Nuclear 

Lignite 

Hard Coal 


Other RE 


Gas 

Oil 

Wind

of this electricity would be €421 bn. In this regard the 

infrastructure costs only represent about a fifth of the 

electricity value that is generated. 

Please note that in the calculation of the net investment 

for the overall grid design, only the additional 

benefits of the OffshoreGrid overall design were taken 

into account. As the ENTSO-E TYNDP interconnector 

plans were included in the base cases (Radial reference 

scenario and Hub Base Case scenario 2030), 

their system benefits were not explicitly calculated. 

4.5.6 Power system impact of the 

offshore grid 

The power market model provides a large number of 

interesting results. In the following paragraphs, the impact 

of the offshore grid and the chosen design on the 

power system and the infrastructure is investigated, in 

particular for the following issues: 

• Utilisation of wind farm grid connection cables: The 

offshore grid combines the transmission of wind 

energy and the trade of electricity, and thus leads 

to an increase in wind farm connection cable utilisation 

(full load hours of the cable use). 

• Influence on energy mix: As the offshore grid enables 

more trade of electricity over large distances, 

power can be generated where it is cheapest. 

• Flexibility provision: The offshore grid leads to the 

spatial smoothing of short term renewable energy 

variations, as discussed in section 4.1. As such, 

this reduces the balancing needs in the system. 

The utilisation of wind farm grid connection cables and 

the influence of the offshore grid on the energy mix 

are explained below. A more detailed analysis on the 

balancing of wind power can be found in Annex D.III.V. 

Utilisation of cables for wind farm grid 

connection 

As discussed above, some wind farm hubs are nodes 

within the offshore grid and thus not only transport 

wind energy but are also used for trade. Accordingly, 

41 For individual wind farm connections, the capacity of the wind farm connection cable is 90% of the wind farm capacity, as described 

in Deliverable 5.1, available online [26]. 


the utilisation of the cables connecting these hubs 

changes with the development of the offshore grid as 

also the power flows change. 

Table 4.7 illustrates the increase in utilisation of some 

representative wind farm hub connection cables that 

connect the hub to shore. Of course only those hubs 

were selected that connect to more than one country 

as otherwise the utilisation of the cables would be 

independent of the offshore grid development and remain 

constant. The analysis compares the utilisation 

of the cables in the hub base case scenario with the 

utilisation after step 2 and step 3 within the Direct 

and Split Design (compare sections 4.5.2 and 4.5.3). 

For the values marked in the table, the wind farm connection 

is just an individual connection to one onshore 

connection point within the associated design step 41 . 

No electricity is traded via these lines and therefore 

these do not exhibit changes in utilisation as long 

as no wind power is curtailed due to onshore grid 

constraints. 

Typically the utilisation of the wind farm cables to 

shore will increase when the hub is connected to an 

offshore grid or to another shore. This is because the 

connections are then also used for electricity trade. 

On average, for the connections that are coupled to 

another point in the Direct Design (before the mesh), 

the utilisation rate is improved with 22%. For the Split 

Design the increase is even larger (29.7%). Adding the 

mesh in step 3 to the design improves the utilisation 

rate with about 3-4% in both cases. 

As can be seen from the table, there are some exceptions 

which see rather a decrease of the utilisation 

rate when adding the mesh (e.g. the connection of 

Norfolk B to Great Britain, or the connection of Aegir 

to Norway). There are always two possible reasons for 

these: 

• The mesh connection is mostly used to send the 

wind energy to a higher priced area so that the original 

individual cable connection is used less, 

77

esults 

• There are other connections that already take up 

the price difference and provide the arbitrage needed 

so that no trade is necessary any more. 

Where such impacts can be expected, a detailed assessment 

should be done to optimise the rating of 

the different lines. For example, in the exceptions described 

above, a lower cable capacity from the wind 

farm to shore can be a better option. 

Offshore grid influence on energy mix 

Improved grid infrastructure enables more power flow, 

and therefore more flexibility in the power production. 

This in turn gives reduced system costs, since it allows 

a better use of the generation units with lower 

marginal costs. Figure 4.39 shows how large the 

change in production is for each technology in the energy 

mix. 

As expected, it is clear that the offshore grid facilitates 

a shift from more expensive gas and hard coal to 

cheaper generation, in particular “Other RE”. The category 

“Other renewables” stands in this case for all 

renewable technologies that are neither wind energy 

nor hydro, such as bio energy, solar, tidal and wave. 

This shift in generation mix can be best understood 

when considering the marginal costs for the generation 

technologies, which are: 

• Other renewables ~ €50.6/MWh 

• Lignite coal ~ €58.3/MWh 

• Hard coal ~ €62.0/MWh 

• Gas ~ €70/MWh 

The small increase in wind power is due to reduced 

grid constraints because of the offshore grid 42 . The 

increase is indeed small compared to the total annual 

production of 530 TWh. The change in hydro power 

output is due to pumping facilities. 

The change of the energy mix is bigger for the Direct 

Design since it involves a higher interconnection capacity, 

as described above. 

4.5.7 Conclusion and discussion 

Summary of the techno-economic 

conclusions 

Two methodologies have been assessed for the development 

of an offshore grid in northern Europe. The 

first approach, the Direct Design, was based on the 

consideration that currently various direct countryto-country 

interconnections are being developed. In 

order to develop a most realistic approach the most 

beneficial direct interconnectors were identified in a 

first step. After that, hub-to-hub and tee-in solutions 

as well as a mesh were assessed. The second approach, 

the Split Design, is based on results of the 

case-independent model (see section 4.4). The caseindependent 

model showed that it is promising to 

create interconnections by splitting the connection of 

large wind farms far from shore to two countries. This 

way, the wind farm is connected to shore and at the 

same time an interconnector is established at relatively 

low costs. 

A high number of interconnection cases and design 

variations have been assessed with the model. They 

have been narrowed down from the vast number of 

possible designs by considering the results of the 

case-independent model. Furthermore the electricity 

price levels within the different countries were analysed 

to identify the most promising trading corridors. 

The results confirmed that it can indeed be beneficial 

from a European welfare point of view to tee-in wind 

farms, to interconnect countries via wind farm hubs, 

and to split the connection of large wind farms in order 

to connect it to two shores. 

As shown in section 4.5.4, the conclusion of the caseindependent 

model on the split wind farm connections 

is confirmed, by the relative comparison of the six split 

wind farm connections in the Split Design versus the 

corresponding direct interconnectors in the Direct 

Design. The average reduction in CAPEX from choosing 

a split connection over a direct interconnector is 

more than 65%, while the reduction in system cost 

42 There are fewer constraints so that more wind power can be transmitted. Due to the interconnections, some of the wind generation 

that would otherwise be curtailed because of the 90% assumption can now also be transported. 


is only about 40% lower on average. A comparison of 

the benefit per invested Euro of CAPEX revealed that in 

the Split Design for each Euro spent about 3 Euros are 

earned as benefit over the lifetime of 25 years, while 

for the Direct Design these are only 2.8 Euros. Thus, 

the Split Design is slightly more cost-effective. 

In conclusion, both developed overall grid designs 

prove to be highly cost-effective and largely reduce 

the system generation costs. Both designs return the 

investment made within short time and lead to large 

net benefits. 

Total costs 

The overall costs for the Direct Design are about 

€86 bn and €84 bn for the Split Design respectively. 

This includes investment costs for the Hub Base 

Case scenario as a starting point which represents 

connection of 126 GW of offshore wind as well as the 

ENTSO-E TYNDP interconnectors. 

The costs for a further interconnected grid built on top 

of this Hub Base Case are only €7.4 bn for the Direct 

Design and €5.4 bn for the Split Design. These relatively 

small additional investments generate system 

benefits of €16 bn (Split Design) and €21 bn (Direct 

Design) across a lifetime of 25 years – benefits of 

about three times the investment. 

The total circuit length of the Split and Direct Design 

is about 30,000 km (10,000 km AC, 20,000 km DC). 

The hub base case scenario however already accounts 

for 27,000 km, while the additional circuit 

length to build the Direct or Split Design is only about 

3,000 km. The overall offshore interconnection capacity 

is boosted from the existing 8 GW to more than 

30 GW in the Direct and Split Design. 

The investments into offshore grid infrastructure 

have to be put into relation to the offshore wind energy 

produced. The offshore wind farms considered in 

OffshoreGrid produce about 530 TWh annually which 

is almost the annual consumption of Germany. Across 

25 years this amounts to 13,300 TWh. Assuming 

today’s average spot market price of €50/MW the 

value of this electricity is €421 bn. In this relation the 


infrastructure costs only represent about a fifth of the 

electricity value that is generated offshore. 

Discussion of the results in a broader 

context 

• Strong business case of split wind farm 

connections 

As clearly shown by the OffshoreGrid results, any 

interconnector has in general a negative impact on 

the already existing interconnectors. This is a serious 

investment risk for the developer. The business 

case of any new interconnector should therefore be 

very strong to withstand the negative impact of future 

infrastructure measures. The split wind farm 

connections are ideal candidates for such strong 

business cases since both the wind farm connection 

and the economical trade add to the benefits 

of the project. It is less dependent on trade than 

a direct interconnector, and can therefore still be 

beneficial even with lower price differences. 

• Merchant interconnector concept to be reviewed 

Following the same reasoning on the negative impact 

of new interconnectors on the existing ones, 

the policy for merchant interconnectors which receive 

exemption from EU-regulation should be 

reviewed. Investors in and owners of merchant 

interconnectors are encouraged to obstruct to any 

new interconnector, as this will reduce the price difference 

and thus their return on investment. This 

can put the strive to have a single EU market for 

electricity seriously at risk. 

• beyond the economics – technical advantages of 

an interconnected grid 

Apart from the techno-economic reasons as described 

above, the Split Design provides further 

advantages. It reduces the total cable length and 

thus provides environmental benefits. Moreover, it 

improves the redundancy for the wind farm connection 

as two connections to shore are established. 

This improves system security and reduces the system 

operation risks, the need for reserve capacity, 

and the loss of income in case of faults. 

79

esults 

These merits also hold for tee-in connections and 

hub-to-hub connections. It should be highlighted 

that they need to be taken into account when assessing 

single concrete cases. 

• Interconnected grids require an appropriate regulatory 

framework 

On the other side, tee-in solutions, hub-to-hub 

solutions and split wind farm connections are confronted 

with the unsolved problem of regulatory 

framework and support scheme incompatibilities 

between European countries (also see section 

5.1.2). The reason is that renewable energy that is 

supported by one country can now flow directly into 

another country. The country paying for the generated 

energy cannot “enjoy” all benefits that go along 

with it. 

For split wind farm connections, this is even more 

difficult. The reason is that the ideal split connection 

links the wind farm to two different countries, 

and the connection capacity to the country in which 

the wind farm is located is reduced. The question 

is then e.g. which support scheme is applied and 

to which national RES account the produced wind 

energy is added to. These complexities can significantly 

slow down the development of integrated 

and especially split connections. Therefore solutions 

at international or bilateral levels have to be 

developed as soon as possible. 

An offshore grid will be built in modular steps. Every 

new generation unit, interconnection cable, political 

decision or economical parameter has a serious impact 

on both the future and the existing projects, and 

thus influences the design of a future offshore grid. 

However, the two designs presented bring useful understanding 

and conclusions that allow bringing the 

actual developments forward with modular steps in 

the best possible way. 


TOWArDS AN OFFSHOrE GriD – 

FurTHEr cONSiDErATiONS 

• challenges and barriers 

• Ongoing initiatives – policy – industry 

Photo: C-Power

Towards an Offshore Grid – Further considerations 

5.1 Challenges and barriers 

OffshoreGrid focuses on the techno-economic assessment 

of the offshore grid. Policy trends, regulatory 

issues and industry developments are taken into account 

directly or indirectly, for instance during the 

scenario development (nuclear phase outs, support 

schemes and their development), or while identifying 

concrete cable paths when the maritime spatial 

planning was analysed. This ensures technical and 

political feasibility of the project, but at the same 

time asks for adaptations or discussion on some 

regulatory, industry or policy issues. The OffshoreGrid 

consortium identified a optimal offshore grid design. 

Its realisation within a reasonable time frame raises 

further challenges, as discussed in the table below. 

These challenges and issues are sorted according to 

the following categories: 

• Operation and maintenance of an offshore grid and 

further technical challenges 

• Regulatory framework and policy 

• Market challenges and financing 

• Offshore industry supply chain 

The relative magnitude of these challenges are outlined 

in Table 5.1, as split into the four categories 

listed above. 

5.1.1 Operation and maintenance of 

an offshore grid and further technical 

challenges 

For the installation of an international offshore grid, 

various challenges regarding operation and maintenance 

as well as technical barriers have to be 

overcome. 

Offshore grid maintenance 

Offshore grid faults in times of high wind penetration 

have to be counteracted with quick and large primary 

control reserves. Whether these primary control reserves 

are already present at all sites is questionable. 

If not, their construction or market integration is a necessary 

condition for maintenance of an offshore grid. 

TAblE 5.1: chAllENGES ON ThE WAY TOWARdS ThE 

OFFShOREGRId dESIGN 

• = Small challenge 

•• = Medium challenge 

••• = Large challenge 

The categorisation of the challenges from small to 

large challenges is based on a qualitative assessment 

of the OffshoreGrid consortium. It is understood 

as guidance for the reader in order to identify the key 

issues that need concerted attention. 

Operation and Maintenance of an offshore grid and 

further technical challenges 

• Offshore Grid Maintenance 

••• Timing of technology development 

•• Commodity Prices 

• Standardisation 

••• Onshore bottlenecks 

regulatory Framework and Policy 

••• Support Scheme 

•• Permitting 

Operational responsibilities and 

•• 

offshore grid codes 

Market challenges and Financing 

••• Financing the large investments 

••• Capital attraction 

Supply chain 

•• Supply bottlenecks 

The time needed to repair offshore grid outages can be 

significantly longer than would be the case for onshore 

grid maintenance, due to difficulties in accessing the 

equipment offshore (cables and converters). However, 

as the fault can be isolated, the downtime only affects 

an isolated section while the remaining grid can return 

to operation. 

The maintenance costs for the offshore grid will generally 

be higher than for the onshore grid, particularly 

due to small weather windows and a small number of 

capable firms. 

At the aggregate level, offshore grid maintenance issues 

are regarded by OffshoreGrid consortium to be a 

small barrier for an offshore grid. 


Timing of technology development 

The timing of technology development has been found 

by the OffshoreGrid consortium to be a large challenge 

for an offshore grid. There is a variety of new 

technologies needed for safe and secure offshore grid 

operation, particularly with respect to power flow control 

mechanisms, security issues, increased capacity 

and reduction of energy losses. 

The key issue to be tackled is multi-terminal operation. 

So far, fast DC breakers are not fully developed 

and multi-terminal operation is not possible. In case 

of an offshore grid failure the complete grid has to be 

de-energised, the fault has to be isolated, and only 

then can the offshore grid be loaded again. This can 

also have serious impact on the onshore grid stability 

due to frequency problems. Furthermore it should 

be highlighted that TSOs do not have any experience 

with multi-terminal operation based on HVDC VSC 

technology. 

The timing of technology development will depend on 

the likely order value, which in turn depends on the 

connection method the offshore industry adopts. For 

example the adoption of a model whereby offshore 

wind farms are clustered around offshore transmission 

hubs may drive an increase in the capacity of 

individual VSC converter stations, whereas a continuation 

of the trend of individual wind farm connection 

may not. 


Commodity prices 

The overall cost of the offshore grid is largely influenced 

by the cost of the key raw materials, most 

notably the raw materials used in HVDC and HVAC 

subsea cables, as they form by far the largest component 

of the offshore grid. Two metals tend to be used 

to form the conductors in power cables, copper and 

aluminium. The superior conductivity of copper means 

that more electric current (and hence more power) can 

be passed down a copper conductor of certain cross 

sectional area than down an aluminium conductor of 

the same size. This means that copper cables are 

smaller than the equivalent aluminium cables which 

can make transport and installation easier, both important 

and expensive considerations in the offshore 

environment. The surge in global demand for copper 

however has not only driven the price of copper to 

peak levels, but also introduced significant volatility in 

the pricing (See Figure 5.1 below). Any manufacturer 

using significant amounts of copper as a raw material 

would obviously offset this price risk in the equipment 

quotes, potentially pushing up the price of many of 

the pieces of equipment required for an offshore grid. 

Indeed many recent subsea cable orders have been 

specified with aluminium, primarily because of the 

high copper price. 

At the aggregate level, the future development of key 

commodity prices is assessed by the OffshoreGrid 

consortium as a medium barrier for an offshore grid. 

FIGURE 5.1: PRIcE OF cOPPER ON ThE lONdON METAl EXchANGE OvER ThE lAST TWENTY FIvE YEARS (SOURcE: WIkIPEdIA FROM 

lME SOURcE dATA) 

83


Standardisation 

The adoption of common standards across the 

European sphere or even globally, should result in 

more ‘standard’ designs. The standardisation should 

in particular focus on functionalities as e.g. for: 

• fault behaviours 

• system protection schemes 

• control and protection 

Standardisation can reduce costs and also facilitates 

interconnectivity offshore. In particular it allows offshore 

wind farm and grid connection developers to buy 

equipment from different suppliers instead of ordering 

from a small group of manufacturers that offer turnkey 

solutions, for instance for HVDC VSC connections. 

At the same time it is important to keep the standardisation 

to the necessary minimum in order not to 

hamper innovation. Therefore OffshoreGrid recommends 

focusing on standardisation of functionalities 

of equipment rather than defining concrete technical 

specification. This allows manufacturers to develop 

different technical solutions while still facilitating the 

interoperability of equipment. 

Standardisation has been assessed by the OffshoreGrid 

consortium as a small barrier. 

Onshore bottlenecks 

A strong onshore grid is needed for the safe transmission 

of offshore power from the coast towards the 

onshore load centres. For Germany this was worked 

out during in-depth assessments within the dena Grid 

Study I and dena Grid Study II [31], proving the need 

for huge transmission capacity from the north to the 

south 43 . But the need for onshore transmission is also 

crucial in other European countries. In many European 

countries the necessary onshore grid reinforcements 

are often delayed due to low public acceptance. 

Without the timely development of a sufficiently strong 

onshore grid, offshore grid development is put at risk. 

Therefore, onshore bottlenecks are regarded by the 

OffshoreGrid consortium as a large barrier for an offshore 

grid. 

5.1.2 Regulatory framework 

and policy 

An offshore grid involves different countries and transnational 

markets and a variety of support schemes 

and regulatory frameworks. The large diversity across 

Europe is summarised in Figure 5.2. Further details 

are listed in Table 14.1 in Annex E 44 . The difference 

in national regulatory systems and support schemes 

and in particular their incompatibility can in some cases 

be a barrier for the construction of an offshore grid 

as outlined below. 

Support scheme 

Most countries use feed-in tariffs, but certificate or 

bonus systems as well as combined systems are also 

implemented. The difference of support schemes is 

not per se a hindrance for the construction of an offshore 

grid and in most cases specific national support 

schemes are adapted to the specific national needs. 

For the development of an offshore grid it is crucial to 

ensure their compatibility. The OffshoreGrid consortium 

understands the compatibility of support schemes 

as the possibility to allow offshore wind farms to be 

connected to two or more countries either directly or 

via an offshore grid without endangering the financial 

support for the offshore wind farm. The support 

should furthermore be guaranteed independently of 

the electrical power flows and whether the offshore 

wind power is sold across national borders. 

The geographic scope of national offshore support 

schemes diverges considerably across Europe. In 

most countries support schemes are limited to the 

territory or the electricity system of the country. This 

43 The German decision on the nuclear phase-out might even enforce the need for north-south transmission, as most of the nuclear 

power plants are located in the south. 

44 A detailed overview over national support schemes, connection regulation and trade limitations is given in Deliverable 6.1 [29]. 


FIGURE 5.2: OvERvIEW ON OFFShORE WINd SUPPORT SchEMES ANd GRId cONNEcTION 

hinders for instance the installation of wind farms 

outside national territories of one country while connecting 

it to this country. International agreement and 

consolidation on this issue is greatly needed. 

It should be mentioned that besides the incompatibility 

of support schemes, also unaligned national 

offshore wind energy development goals can hamper 

the development of an offshore grid. This is because 

strategic cross-border coordination with compatible 

offshore goals, siting and timing can strongly support 

the offshore grid development with offshore wind farm 

clusters as major nodes. 

Permitting 

The permitting processes for offshore wind farms and 

their connection to onshore landing points differ widely 

across countries. This represents a medium barrier 

from the point of view of the OffshoreGrid consortium. 

There is a wide variety in the number of national executive 

authorities involved in each country, and not 

all countries carry out maritime spatial planning. This 

causes the national permitting processes to differ in 

level of detail, duration and costs, and they are largely 

unsynchronised between authorities. 


In most countries however the grid connection responsibility 

lies with the national TSO who is obliged to 

provide connection to offshore wind farms. This facilitates 

a coordinated joint action among the responsible 

TSOs which can for instance be led by ENTSO-E. 

Operational responsibilities and offshore 

grid codes 

The clear allocation of operational responsibilities between 

national TSOs is seen as a medium barrier for 

an international offshore grid. Also, the harmonisation 

of offshore grid codes used represents a challenge. 

The possibility of setting up an internationally owned 

and operated offshore TSO is currently discussed 

[46]. The development of European network codes as 

initiated by the European Commission is a first step 

towards overcoming this challenge. For instance the 

grid code on the connection requirements for offshore 

wind turbines across Europe is planned to enter into 

force in 2011/2012. Additional network codes, for example 

codes for the grid operation or a network code 

on electricity markets may further enhance the coordinated 

planning of an offshore grid as well as its save 

operation. 

85


5.1.3 Market challenges and 

financing 

Economic barriers, due to market frictions or failures 

and unfavourable financing conditions, hinder the installation 

of an offshore grid in many ways. 

Financing the large investments 

As can be seen from the results of this report, the 

establishment of an offshore grid is going to be expensive. 

This is largely due to the large amounts of 

equipment required, but also to the high cost of both 

the equipment costs and the installation costs of this 

equipment in an offshore environment. 

The overall (calculated) benefits of an international offshore 

grid from the system perspective cannot directly 

be returned to an investor. Still these huge investments 

are needed. Therefore an indication of long-term commitment 

and reliability in national offshore policies is 

needed to attract investors. Otherwise, investments 

in onshore and offshore grid infrastructure will not be 

made in sufficient magnitude. In addition, it may be the 

case that publicly funded securities are needed to give 

a break-through for pioneering offshore investments. 

At the aggregate level, raising enough funds for an 

offshore grid is assessed by the OffshoreGrid consortium 

as a large challenge. The commission started to 

tackle the problem in the energy infrastructure package 

[23]. 

Capital attraction 

The offshore industry faces ongoing up-front financing 

problems for offshore wind energy and grid projects 

due to the high risks that come along with it. Currently, 

the finance industry spreads its risk conservatively 

due to instability of credit markets and asks for high 

risk premiums. 

Fundraising for offshore projects is additionally hindered 

by the long-term uncertainty over offshore wind 

farm development and the available locations for these 

projects. The risks of stranded investments remain 

comparatively high. Therefore, the barrier of capital 

attraction is assessed as large by the OffshoreGrid 

consortium. 

5.1.4 Supply chain 

There are relatively few manufacturers of some of 

the key elements that will be required to create an 

offshore grid, with correspondingly few manufacturing 

facilities and hence elevated demand for few manufacturing 

slots. An expected increase in demand for 

these technologies both in Northern Europe and globally 

means that prices will remain high and delivery 

times to projects constrained, unless the manufacturers 

have sufficient confidence in the market to justify 

investment to expand their manufacturing base. This 

conundrum remains one of the key barriers to not only 

reducing the cost of individual components, but also 

to achieving an offshore grid in the North and Baltic 

Seas. 

Supply bottlenecks 

Offshore wind energy is considered a cornerstone of 

European energy policy, however it still needs development 

and experience is needed in order to reduce risk 

estimations for investments. The envisaged 150 GW 

of installed wind capacity and the necessary transmission 

capacity needed to realise the proposed offshore 

grid design in 2030 is enormous, and the demand for 

equipment and trained personnel along the supply 

chain will be huge. 

Currently it is noticed that there are supply chain bottlenecks 

for the main components of HVDC technology 

which can slow down the development of offshore 

wind farm connections. For singular cases it might be 

necessary to fall back upon AC connection concepts 

until the supply chain is fully able to deliver the requested 

equipment on time. 

Due to today’s uncertainties, some supply chain 

manufacturers are hesitant to carry out the needed investments 

to meet future demand. Therefore there is 

a risk that supply chain bottlenecks endanger continuous 

and steady development towards the envisaged 

efficient scenarios in 2030. 


In particular, the development of appropriate harbour 

infrastructure and the number of laying vessels or 

ships capable of transporting offshore wind turbines 

are significant bottlenecks for an offshore grid. 

Supply bottlenecks are regarded by the OffshoreGrid 

consortium as a medium barrier for an offshore grid. 

5.2 Ongoing initiatives – 

policy – industry 

First of all it has to be highlighted that apart from 

OffshoreGrid, there are few studies that analysed cost 

and benefits of an offshore grid. 

• The PhD thesis by Gregor Czish [34] and the 

European IEE-funded project TradeWind [36] have 

briefly looked into the issue. Both studies outline 

first analysis, but no specific research was carried 

out. 

• Greenpeace has developed a map of a possible offshore 

grid [35]. If it were to be built with 6,200 km 

of offshore electricity cables, the cost is estimated 

at about €15-20 bn. 

• In February 2011, ENTSO-E published its views on 

offshore grid development in the North Seas [45]. 

Its initial view is that an integrated approach can 

deliver capital savings in the order of 10%. 

• The initiative ‘Friends of the Supergrid’ has published 

a position paper on a first phase of the 

supergrid [44]. The design is based on connecting 

23 GW of offshore wind from the Firth-of-Forth, 

Dogger-Hornsea, Norfolk Bank, German and Belgian 

Offshore clusters using technology expected to 

be available between 2015 and 2020. FOSG emphasises 

the need to connect to the large energy 

storage facilities in Norway. According to their estimates, 

the grid tariffs will need to rise by €0.0023 

per kWh to recover the costs. 

The OffshoreGrid study is clearly needed to advance 

the discussion and provide input for policy and industry 

discussion. Some of the ongoing initiatives are 

mentioned below. 


Policy initiatives 

Since 2009 the analysis of an offshore grid is a focus 

of attention on a European and national policy level. 

One of the European Commission’s goals is to design 

a single integrated European market for electricity. An 

offshore grid in Northern Europe, interconnecting offshore 

wind and national power systems, is seen as 

vital in achieving this goal. The European Commission 

thus took a leading role by fostering discussion in different 

working groups. They also provide funding for a 

variety of projects to investigate relevant questions, 

such as optimal grid design (OffshoreGrid), questions 

concerning offshore wind potential (WindSpeed, [37]) 

and maritime spatial planning (Seanergy 2020, [38]). 

Within the framework of the Trans-European Energy 

Networks for Electricity (TEN-E), a coordinator has 

been assigned to coordinate all activities related 

to Baltic and North Sea offshore wind connections. 

The coordinator, Mr. Adamowitsch, has started a well- 

frequented working group with regular meetings in 

which research, industry and policy representatives 

discuss barriers, challenges and solutions for a future 

offshore grid. The OffshoreGrid consortium actively 

follows this working group and provides input and 

presentations. 

Furthermore, at the end of 2010, a new infrastructure 

package has been published by the European 

Commission. It involves a Communication on offshore 

grids [23], and sets the framework for further 

policy actions. In the Communication, the Commission 

defines 8 EU priority corridors for the transport of electricity, 

gas and oil. One of these priority corridors is an 

offshore grid in the Northern Seas. The OffshoreGrid 

consortium actively supported the European 

Commission in the policy making process. Specific 

questions were studied upon request and new results 

were exchanged proactively. The text and recommendations 

in [23] are based on the OffshoreGrid Draft 

Final Report [27]. 

There is also movement on the regional level. What 

originally started in the Pentalateral Energy Forum 

(Governments, TSO’s and regulators of BE, FR, NL, LU 

87


and DE) under the initiative of the Belgian Minister 

of Energy, has evolved into a political initiative with 

all ten countries around the North and Irish Sea (BE, 

FR, NL, LU, DE, UK, IR, DK, SE and NO). The North 

Seas Countries’ Offshore Grid Initiative (NSCOGI) 

aims at coordinating, on a multilateral level, offshore 

wind and infrastructure developments in the North 

Sea. It is more specifically targeted at achieving a 

common political and regulatory basis on offshore infrastructure 

development within the region. A common 

Memorandum of Understanding between all parties 

has been signed at the end of 2010 [39]. Much is 

expected from this initiative for the facilitation of real 

developments. In this framework, TSOs will carry 

out a cost-benefit analysis by December 2012. The 

OffshoreGrid consortium is in regular contact with 

Working Group 1 of the NSCOGI on Grid Configuration. 

The preliminary outcomes have been presented to this 

working group, and a session on the final results will 

be held in October 2011. 

Industry level 

As imposed by law under the Third Legislative 

Package on European Electricity and Gas Markets 

[40], European Transmission Grid Operators (TSOs) 

for electricity have united under ENTSO-E [41]. This 

organisation improves cooperation across national 

borders, and is thus crucial for the development of 

offshore electricity grids. Within ENTSO-E, two working 

groups are relevant in this respect: 

• Regional Working Group North Sea under the 

System Development Committee, 

• WG 2050/Supergrid under the System Development 

Committee. 

The regulators cooperate voluntarily via the Council of 

European Energy Regulators (CEER). A key objective of 

the CEER is to facilitate the creation of a single, competitive, 

efficient and sustainable EU internal energy 

market that works in the public interest. The European 

Regulators’ Group for Electricity and Gas (ERGEG) was 

set up by the European Commission in 2003 as its advisory 

body on internal energy market issues. ERGEG 

launched 7 Electricity Regional Initiatives (ERI, [9]), 

with the aim to speed up the integration of Europe’s 

national electricity markets. Under the European 

Commission’s Third Package [40], all European regulators 

are now united in the Agency for the Cooperation 

of Energy Regulators (ACER, dissolving ERGEG). ACER 

was created in 2010, as imposed by the 3rd package, 

to fill the regulatory gap on cross-border issues 

and should oversee the cooperation between the 

TSOs. Although there are various challenges to face 

on regulatory level (cost allocation and profit margins, 

compatibility in renewable energy support, etc.), action 

on offshore grid issues on the regulator’s side is 

currently very limited. 

Finally, the initiative ‘The Friends of the Supergrid 

(FOSG)’ [42] combines companies in sectors that will 

deliver the HVDC infrastructure and related technology 

with companies that will develop, install, own and 

operate that infrastructure. They have joined because 

of a mutual interest in promoting and influencing the 

regulatory and policy framework that is required to enable 

large-scale interconnection in Europe. 


cONcLuSiONS AND rEcOMMENDATiONS 

• Wind farm hubs 

• Tee-in solutions 

• Hub-to-hub solutions 

• Overall grid design 

• Overall recommendations 

Photo: Vestas

conclusions and recommendations 

The OffshoreGrid project provides concrete recommendations 

and guidelines on the topology and 

dimensioning of an offshore grid in northern Europe. 

Furthermore recommendations for policy, industry and 

the financing sector are also made in order to ensure 

that the offshore grid will be built quickly and efficiently. 

Developing offshore grid infrastructure is a complex 

process. On the one hand there are the techno- 

economic issues assessed in OffshoreGrid, with a 

large amount of possible configurations and design 

options that influence each other and are heavily dependent 

on various factors 45 . On the other hand there 

are issues concerning the political and regulatory 

framework, financing, supply chain and operation to 

be resolved. 

The development of an optimal grid design and modular 

planning is therefore only a first step. Further 

challenges are in store during the financing process, 

the grid construction as well as grid operation and 

maintenance. 

OffshoreGrid drew up a design for an offshore grid and 

identified several case-independent conclusions that 

can provide insight and serve as concrete guidelines 

for specific cases. 

The main results, conclusions and recommendations 

of OffshoreGrid study are summarised in this chapter. 

6.1 Wind farm hubs 

Key results on wind farm hubs 

• Clustering of wind power projects is advantageous 

in many cases. The magnitude of the benefit depends 

on the hub distance from shore, and the 

distance between the individual wind farms (capacity 

concentration in the same area). 

• A shared hub connection is most advantageous 

when a high amount of wind farm capacity is concentrated 

in a small area and when the cluster 

capacity is about the size of the standard available 

HVDC VSC systems. 

• Integrating a wind farm into a nearby hub is economically 

advantageous for wind farm to hub 

connection distances of less than 20 km. 

• In addition, a hub solution may be beneficial for reasons 

other than cost. Offshore hubs can help to 

mitigate the environmental and social impact of laying 

multiple cables through sensitive coastal areas 

and allow for more efficient logistics during installation. 

These benefits need to be balanced with the 

risk of stranded investments. 

• Even if the construction of some wind farms within 

a hub is largely delayed, the hub solution can still be 

beneficial compared to individual connections. This 

even holds for some cases where some of the wind 

farms are not built at all (stranded investment). The 

impact of stranded investments or temporary connection 

over-sizing is limited, especially for big wind 

farm groups far from shore. 

Recommendations on wind farm hubs 

In view of the large potential benefits to be gained by 

connecting wind farm clusters via hubs, it is essential 

that political and regulatory strategies to foster their 

development are adopted. 

• Where wind farm concession areas have already 

been largely defined, regulation should be designed 

such that hub connections will be favoured over 

individual wind farm connections wherever this is 

beneficial with regard to infrastructure costs. Today 

the economic assessment of hub connections 

is still limited to “obvious” cases. OffshoreGrid 

recommends extending the assessment scope of 

possible hub projects as far as possible. 

• In countries where strategic siting and granting 

of concessions is not yet in place, policy makers 

should aim for fewer areas with a larger number 

of concentrated wind farms, with projects within an 

area scheduled for development at the same time 

rather than in more and smaller dispersed concession 

areas. In line with the expected development 

of HVDC VSC technology, the optimal installed 

capacity in an area should be around 1,000 MW 

45 Examples include price differences between countries, geographic parameters, market design, investments in new onshore power 

generation capacity, political decisions such as e.g. the phase out of nuclear energy, etc. 


for areas developed in the coming ten years and 

2,000 MW for areas developed after 2020. 

• When differences in timing of construction exist 

between the wind farms in a hub or when delays occur, 

it should be investigated whether a hub is still 

beneficial. Short delays or delays of smaller wind 

farms generally do not impact the economics too 

much. However, governments should support simultaneous 

development as much as possible in order 

to reap the maximum benefits of the synergies of 

a combined solution. OffshoreGrid recommends 

assessing hub solutions even for projects that are 

built within time spans of more than 10 years. 

• National borders should not be a barrier for a hub 

connection solution. If for instance a wind farm 

is built close to the border and close to a wind 

farm cluster in a neighbouring country, it is recommended 

to construct cross border hub solutions. 

Regulatory frameworks, support scheme issues 

should allow these solutions. 

• In order to improve conditions for cross border 

meshed grid designs. European Member States 

have to discuss how to distribute costs or funding 

incentives for joint infrastructure measures. 

Furthermore it has to be agreed to which country 

the renewable energy generated is credited. 

6.2 Tee-in solutions 

Key results on tee-in solutions 

• Connecting an offshore wind farm to an interconnector 

by means of an underwater tee-joint is 

technically possible irrespective of whether the 

interconnector itself uses HVDC CSC or VSC technology. 

For a configuration requiring circuit breakers 

on a platform, VSC technology will become the preferred 

solution. 

• For reasons of operational security and fault handling, 

TSOs may generally prefer a solution with 

circuit breakers to reduce fault propagation. A full 

cost benefit analysis would be required to justify 

the additional cost and consequent reduction in net 

benefit incurred. 

46 As shown in Chapter 4, actual numbers are greatly dependent on case-specific parameters. 


• Whether tee-in connection of offshore wind farms 

to interconnectors is beneficial depends on the 

associated constraints for international power exchange 

and the substituted infrastructure costs. 

When connecting an offshore wind farm hub to an 

interconnector, the availability of the interconnector 

for international exchange is reduced in the direction 

towards the country to which wind farm was 

connected originally (trade constraint). On the other 

hand, infrastructure cost savings incur as the tee-in 

is cheaper than the substituted individual connection, 

due to the fact that for the beneficial cases 

the cable length can be vastly reduced (wind farm 

is far from shore but close to interconnector). 

• Tee-in solutions become more beneficial when: 

– Price differences between countries are low 

as trade between the countries would then be 

secondary, 

– The wind farm is far from shore and close to the 

interconnector 46 , 

– The country where the wind farm is built usually 

has the lowest prices of the countries involved, 

– The offshore wind farm generation is inversely 

correlated with the price difference (high wind 

power, low price difference), 

– The wind farm capacity is either low compared 

to the interconnector capacity (low trading constraints), 

or double its size (large infrastructure 

savings); the economically worst case would be 

a wind farm and interconnector capacity of equal 

size, 

– A simple tee-joint is used instead of an additional 

platform (fewer costs but no ability to break 

faults). 

• A special case, which can be considered to be a 

tee-in solution, has been identified for large wind 

farms far from shore. Instead of connecting the 

whole wind farm to one shore, the connection can 

be split and the wind farm can be connected to two 

shores. 

• This way, a wind farm is connected and at the same 

time an interconnector is built that can be used 

when the wind farm is generating less than 50% of 

rated capacity, which occurs about 50-60% of the 

time. 

91


• While the sum of the two cable capacities should 

be a little bit smaller than the wind farm size, the 

individual cable sizes should be decided based on 

the price levels in the connected countries. The 

connection to the country with a higher assumed 

price level across the project lifetime should be 

larger than the connection to the country with a 

lower price level. 

• A detailed case study on the Cobra cable between 

Denmark and the Netherlands was carried out. 

Teeing-in a German wind farm to the Cobra cable 

is identified as beneficial from the point of view of 

European welfare. The case study also confirmed 

the conclusion on the split connection of the large 

wind farms: teeing-in a 1300 MW into the 700 MW 

Cobra cable proved to be the most interesting 

option. 

• Concrete guidelines for pre-feasibility analysis on 

tee-in solutions have been defined and can be 

found on www.offshoregrid.eu. 

Recommendations on tee-in solutions 

• For large wind farms/hubs far from shore, the 

opportunities for splitting the connection to two 

shores and creating an interconnector at the same 

time should be investigated. 

• For small wind farms that are considered to be far 

from shore (e.g. offshore wind to supply oil and gas 

platforms), it should be investigated whether they 

can be teed-in to an interconnector. 

• When deciding between a tee-in solution and a 

split connection (one wind farm connected to two 

shores), the rating of the cable sections at either 

side of the wind farm should be carefully considered, 

based on an individual power market analysis. 

In order to reduce the constraints and maximise 

the benefits, the capacity should be highest at the 

side of the country which usually has the highest 

prices. 

• Interconnectors that are required for international 

exchange or improving security of supply should 

not be delayed and they should be rated as optimal 

for these purposes. If future wind farms are 

considered to be installed close to one of these 

interconnectors, the technology and cable route 

should be anticipated to maximise the future benefits 

of the integrated solution. 

• If a wind farm tee-in produces net benefits compared 

to the conventional connection of the wind 

farm to shore, no technology should be ruled out 

a priori. The decision on which HVDC technology to 

use and on which technical set-up to favour should 

be based on the analysis of all costs and benefits 

including operational implications (e.g. fault handling, 

redundancy, etc), costs of infrastructure, 

electrical losses and available capacity ratings. 

• Tee-in connections are technically feasible and 

economically beneficial in many cases. However, 

incompatible regulatory frameworks and support 

schemes can hinder construction as the developer 

is confronted with large uncertainties, in particular 

in regard to the support or capital attraction due to 

difficult connection barriers. In particular when the 

wind farm in question is connected to an interconnector 

that does not start or end in the country in 

which the wind farm is built, national states might 

be reluctant to support the solution if the renewable 

energy generation is not credited to them. 

These political, support scheme and regulatory 

framework issues need special attention in the 

coming years in order to make tee-in solutions 

possible. 

6.3 Hub-to-hub solutions 

Key Results on hub-to-hub solutions 

• Connecting countries via offshore wind farm hubs 

requires VSC technology and circuit breakers on 

a platform as fault propagation has to be limited. 

This is in particular necessary in order to maintain 

a high grid operation stability and security of supply 

level. 

• Whether a hub-to-hub solution is beneficial over a 

direct interconnector depends on the associated 

constraints for international power exchange and 

the substituted infrastructure costs. While the 

integrated solution reduces the possibilities for 

trade (trade constraint), the infrastructure costs 


are generally lower because the cable length can 

be vastly reduced: individual connection to shore 

is expensive, the wind farm to hub connection and 

the bundled hub-to-shore connection with a large 

capacity are cheaper. 

• Hub-to-hub solutions become more beneficial when: 

– Price differences between countries are low, 

– Countries are far from each other but wind farm 

hubs are close (high cost savings), 

– The wind farm capacity, and thus its connection 

to shore, is high compared to the interconnector 

capacity (low constraints), 

– The wind power is inversely correlated with 

the price difference (high wind power, low price 

difference). 

• In many cases the wind farm hubs will be built first 

to connect national wind farms. The interconnection 

between the hubs is then built later and should 

be dimensioned considering the price levels in the 

countries the hubs are connected to. This is because 

most of the time the power would flow from 

the hub in the country with the lower price to the 

hub in the country with the higher price. Of course it 

would be optimal to additionally dimension the hub 

connection cables according to these considerations, 

as in the case of the “split-cable-connection”. 

But this is only possible in the ideal case when the 

hub-to-hub connection is taken into account at the 

very beginning of the project planning. 

• Ideally, the hub-to-hub connection would be planned 

from scratch which allows the hub-to-shore and 

hub-to-hub connections to be dimensioned according 

to expected price levels in the interconnected 

countries. In general this would mean that the hubto-shore 

connection should be dimensioned larger 

in the country with the higher price level. This is 

in line with the power flow as an additional power 

trade from the country with the higher price level 

would be beneficial. 

• For meshed grid nodes with more than two lines 

coming together, similar conclusions can be drawn. 

The links to the country with the highest prices 

(over the lifetime) should be largest, and the other 

ones can be smaller in dimension. The most efficient 

solution would occur if the sum of all country 

connection cable capacities equals the sum of the 


connected wind farms. This way the additional investment 

in integrated platforms and joints brings 

interconnection between three countries. If larger 

interconnection capacity is needed, some of the 

cables can be oversized. 

• Concrete guidelines for pre-feasibility analysis on 

hub-to-hub solutions have been defined and can be 

found on www.offshoregrid.eu. 

Recommendations on hub-to-hub solutions 

• When hub connections for offshore wind farms are 

developed, the plans should be reviewed by the TSO 

in order to identify possible connection options to 

other wind farms hubs or countries for which there 

is demand for international exchange. 

• Equally, when developing interconnectors, TSOs 

should review the identified concession areas for 

offshore wind and consider the option of developing 

a hub in such an area as a starting point for the 


• If feasible options have been identified, the offshore 

grid developer should carry out a detailed feasibility 

and pre-design study in view of an optimal dimensioning 

of the integrated solution. This may include 

increasing the rating of the hub connection to shore 

in order to satisfy the required demand for international 

exchange. As for tee-in solutions, the focus 

should be on increasing the capacity on the side of 

the country which usually has the highest prices. 

• Offshore grid development should be a joint or, at 

least, coordinated activity of the developers of the 

wind farms and their hubs connections, and TSOs. 

• The North and Baltic Sea countries should adapt 

their regulatory frameworks to foster such a coordinated 

approach. 

• When looking at the interconnection of two hubs in 

different countries: In the case that the hubs are 

built first and the hub-to-hub connection is added 

later on to the existing wind farm hubs, there is 

not much need of additional international coordination. 

In such a case the interconnection would be 

comparable to an onshore cross-border interconnection 

in terms of its legal, regulatory and political 

complexity. 

93


• However the investigation has shown that the ideal 

hub-to-hub connection design takes into account 

hub sizes and the expected electricity price levels 

at the very beginning of the project planning. This 

way not only the hub-to-hub interconnection capacity 

can be optimally dimensioned but also the 

hub-to-shore connections can take into account 

electricity trade across the hub-to-hub connection. 

• To achieve this ideal case, a significant coordination 

effort is needed and the compatibility of the 

support schemes and regulatory frameworks within 

the different countries needs to be checked. The 

reason is that such an ideal long-term planning 

would require strong political and regulatory continuity 

to reduce investment risks. If, for instance, 

the hub-interconnection is not realised in the end, 

the ideal hub-to-shore connection capacity would of 

course be different and thus the design of these 

hubs without interconnection would be suboptimal. 

• Such coordination can be steered in bilateral 

processes with support at European level. 

6.4 Overall grid design 

Key results on overall grid design 

• Building direct interconnections is valid and 

beneficial. 

• Tee-in connections, hub-to-hub connections and the 

special tee-in case of split wind farm connections 

can significantly increase the cost-efficiency of an 

offshore grid, and together form important and beneficial 

building stones for any offshore grid design. 

• The utilisation of offshore wind farm (or hub) connections 

is increased by building connections from 

the offshore wind farm (or hub) to other countries 

or an interconnected offshore grid. 

• An offshore grid allows a shift to cheaper power 

generation. Renewable energy in particular benefits 

from the additional offshore transmission capacity. 

• An offshore grid connects generation in Europe (in 

particular wind energy) to the large hydro power 

“storage” capacities in Northern Europe. This can 

lower the need for balancing energy within the different 

European regions. 

• Two offshore grid methodologies were assessed 

and used to come to a final design. The Direct 

Design builds first on direct interconnections, and 

then integrated solutions and meshed links are 

applied. The Split Design starts by building interconnectors 

by splitting wind farm connections, then 

integrated solutions and meshed links are applied: 

– Splitting wind farm connections to combine 

the offshore wind connection with trade has 

proven to be more cost-effective than building 

direct interconnectors only for trade. The average 

reduction of the CAPEX by choosing a split 

connection over a direct interconnector is over 

65%, while the reduction in system cost is only 

about 40% smaller on average. A comparison 

of the net benefit per invested Euro of CAPEX 

revealed that when splitting wind farm connections, 

each Euro invested is spent 2.6 times 

more effectively. 

– Although less extreme, the absolute comparison 

also proved that the Split offshore grid 

design would be more efficient than the Direct 

offshore grid design. For a CAPEX of €4 bn in 

both designs, the Split methodology leads to an 

extra reduction in system cost of 9% (€944 m 

over 25 years) compared to the Direct Design 

methodology. 

• The overall costs for the overall offshore grid design 

(Direct Design or Split Design) are about €85 bn. 

This includes investment costs for the Hub Base 

Case scenario as a starting point which represents 

connection of 126 GW of offshore wind as well as 

the ENTSO-E TYNDP interconnectors. 

• The costs for a further interconnected grid built on 

top of this Hub Base Case are only €7.4 bn for 

the Direct Design and €5.4 bn for the Split Design. 

These relatively small additional investments 

generate system benefits of €16 bn (Split Design) 

and €21 bn (Direct Design) across a lifetime 

of 25 years – benefits of about three times the 

investment. 

• The total circuit length of the overall grid design 

(Split or Direct) is about 30,000 km (10,000 km 

AC, 20,000 km DC). 

• Investments in offshore grid infrastructure have 

to be put into relation to the offshore wind energy 


produced. The offshore wind farms considered in 

OffshoreGrid produce about 530 TWh annually 

which is almost the annual consumption of 

Germany. Over 25 years, this amounts to 13,300 

TWh. Assuming today’s average spot market price 

of €50/MW, the value of this electricity is €421 

bn. In this relation the infrastructure costs only represent 

about a fifth of the electricity value that is 

generated offshore. 

• Meshed grid designs with three- and four-leg nodes 

can result in high net benefits and large benefit-to- 

CAPEX ratios, as proven by the mesh configuration 

in both the Direct and the Split Design. In both designs, 

the mesh serves primarily as a North-South 

interconnection, which supports the conclusions 

that the North-South wind generation correlation 

was the lowest (see Section 4.1). Moreover, this 

also confirms the need for connection to the flexible 

and cheap Norwegian and Swedish hydro power 

resources. 

• An offshore grid will be built step by step. Every 

new generation unit, interconnection cable, political 

decision or economical parameter has a serious 

impact on both the future and the existing projects, 

and thus influences the design of a future offshore 

grid. However, the two designs presented in this 

report bring useful understanding and conclusions 

that allow the grid development to be brought forward 

with modular steps in the best possible way. 

Recommendations on overall grid design 

• Any interconnector has a negative impact on the 

interconnectors that already exists because they 

reduce price differences between the countries. 

The business case for any new interconnector 

should therefore be very strong to withstand the 

negative impact of future infrastructure measures. 

Split wind farm connections are less dependent 

on the trade than a direct interconnector, and can 

therefore still be beneficial even with lower price 

differences. 

• Following the same reasoning, the policy for 

merchant interconnectors which receive exemption 

from EU-regulation can be questioned. The 


merchant interconnector concept can incentivise 

investments that bear large risks. However, investors 

in and owners of merchant interconnectors 

are encouraged to obstruct any new interconnector, 

as this will reduce their return on investment. 

It is therefore absolutely necessary that there are 

no conflicts of interest, for instance with private investors 

that have key roles in grid planning, grid 

operation or political decisions process for these 

issues. Otherwise the endeavour to have a single 

EU market for electricity is put at risk. 

• In addition to the techno-economic advantages, the 

Split Design has environmental benefits because it 

reduces the total circuit length. Moreover, it improves 

the redundancy of the wind farm connection, which 

improves system security and reduces the system 

operation risks, the need for reserve capacity, and 

the loss of income in case of faults. When doing 

detailed assessments for concrete cases, these 

merits should not be forgotten. These technical 

advantages also come along with tee-in and hubto-hub 

connections and of course in particular for 

the mesh grid design (step 3 of the two design 

approaches). 

• On the other side, tee-in solutions, hub-to-hub 

solutions and split wind farm connections are 

confronted with the unsolved problem of potential 

regulatory framework and support scheme 

incompatibilities between European countries. The 

reason is that renewable energy that is supported 

by one country can now flow directly into another 

country, so that the country paying for it cannot 

“enjoy” all the benefits. For split wind farm connections, 

this is even more difficult as the connection 

to the country in which the wind farm is located 

is reduced. As these complexities add risks to 

the development of integrated and especially split 

connections, they should be solved at international 

or bilateral level as soon as possible. 

• The ongoing development of direct interconnectors 

should not be slowed down, as this concept can 

already be realised today without large wind farms 

far from shore. However it is advisable to anticipate 

tee-in connections for suitable future wind farms. 

95


6.5 Overall recommendations 

Developing integrated solutions requires suitable political, 

regulatory and market conditions. Concerted 

technology development and research is also needed. 

This is in order to provide a stable framework, within 

which both wind power generation and international 

exchange can be at least as profitable as when they 

are carried out independently. 

• Regulatory 

– For solutions that involve two countries, for 

example tee-in and hub-to-hub, the operation 

of the grid can be managed through cooperation 

of the national TSOs, just as they manage 

onshore interconnectors. The grid up to the offshore 

wind farms can be seen as an extension 

of the onshore grid. The interconnector part can 

be seen as a normal cross-border point-to-point 


– For multilateral solutions (fully meshed grid 

design), the operation is more complex and in 

particular in the case of grid faults the fault 

isolation and fault correction have to be well coordinated. 

Very good cooperation between the 

TSOs will be needed to efficiently manage the 

interconnections. A first step in such cooperation 

was already taken with CORESO 47 . 

– Regulatory concepts for efficient ownership 

structures and profit allocation are needed to 

accelerate offshore grid development. If a wind 

farm is teed-in or split to two countries, the electricity 

it produces can be sent to the country with 

the highest price. Thus this would give additional 

benefits to the wind farm operator. At the same 

time the electricity from wind energy constrains 

trade and reduces trading benefits, leading to 

conflicts of interest between the parties involved. 

Thus, profit sharing concepts are needed 

that allow profitable operation of both the interconnector 

and the wind farm, and additionally 

return a significant share of the benefits to the 

consumer within a proper regulatory framework. 

If the latter is not the case, there is the risk of 

low public support (for example in the case of 

47 CORESO S.A. http://www.coreso.eu/ 

Norway where customers will have to pay higher 

prices). 

– Permitting procedures even for national offshore 

hub connections and single wind farms take 

considerable time and effort. The level of complexity 

increases strongly for international grid 

infrastructure. 

– Permitting procedures should be reviewed to 

facilitate international projects. Ideally, the offshore 

project can be handed in for approval in 

an identical form to the authorities of all relevant 

Member States. 

– Such a process should be fostered at national 

level and can be supported at European level or 

regional level, for instance by the NSC’OGI. 

• Political coordination 

– Support for offshore wind energy should be 

made compatible with integrated solutions. The 

offshore wind power generation should receive 

its necessary support irrespective of which 

country the electricity is flowing to. To achieve 

this goal it is not necessary to harmonise the 

European support schemes, but it is necessary 

to make them compatible with one another. 

– Hub-to-hub interconnections, tee-in connections 

and split wind farm connections can be beneficial 

even when the infrastructure elements are 

added to already existent infrastructure, such as 

a tee-in to an existing interconnector or a hubto-hub 

connection to existing wind farm hubs. 

When the interconnection is international, this 

requires bilateral arrangements, adaptations or 

exemptions to the national support schemes. 

– The offshore grid development depends to a 

large extend on a strong onshore grid that allows 

the electricity to be transported further. The 

system should always be considered as a whole 

and it should be emphasised that the development 

of an offshore grid can be supported by 

accelerating the construction of onshore grid 

reinforcements. 

– The optimal offshore grid design depends strongly 

on the timing and location of offshore wind 

farm development. Even though OffshoreGrid 


found that some meshed design and hub solutions 

are beneficial even if the elements to be 

interconnected are built within time spans of up 

to several years, simultaneous development in 

compact areas should be facilitated politically 

if possible. Ideally this coordination would be 

done at international level. The NSC’OGI could 

for instance support such a coordinated planning 

of offshore wind farm development. 

• Market and financing 

– Market coupling with implicit auctioning is 

needed. Interconnection capacity needs to be 

traded day-ahead and intra-day to make optimal 

use of the infrastructure for trade and balancing 

purposes. 

– Market regions have to include offshore areas. 

It is necessary for the price levels between the 

market regions to give investment signals for 

further interconnection, including offshore. 

– Offshore wind energy and in particular a meshed 

international offshore grid lead to large infrastructure 

investments and high risks. Therefore 

investors are reluctant and capital attraction is 

low. The support of pilot projects has already 

been proven beneficial for offshore wind farms 

and should be extended to offshore grid infrastructure 

pilots. In order to put offshore grid 

development on solid ground it is necessary 

for offshore grid infrastructure investments to 

be supported at national or European level. The 

return on investment may further be supported 

by exemptions from regulatory framework rules 

which help to mitigate investment aversions. 

The possibility of such a merchant interconnector 

should however not entail conflicts of interest 

as described above (in the ‘Regulatory’ section). 

• Technology development and Research 

– The timing of technology development is crucial 

for the steady development of an offshore grid. 

Apart from the fast circuit breakers that would 

enhance multi-terminal development, larger cable 

capacities could boost the development of 

such a grid. This development would be driven 


by a growing offshore sector that can rely on a 

continuous offshore technology development. 

Policy makers have to ensure that the conditions 

for offshore wind energy development are stabilised 

in order to lay the grounds for long term 

project and equipment development. 

– Research in many aspects of offshore wind energy 

– such as offshore grid design, offshore 

equipment, offshore operation and maintenance 

concepts, and offshore wind farm control – has 

mostly been funded at national and European 

level throughout the last decade. The research 

carried out has significantly accelerated the 

development of offshore wind energy. It is absolutely 

necessary that this level of research 

support is maintained until offshore wind energy 

can be considered a mature and proven 

technology. 

– The standardisation of offshore grid equipment 

can open the market to further competitors and 

significantly reduce costs. At the same time overstandardisation 

can hamper further innovation. 

– The standardisation issues should be studied 

in detail at expert level in order to define the 

right moment to standardise and the optimal 

standardisation detail. 

Political coordination is required to decide on and 

implement the recommended solutions. So far, the 

overall questions concerning the development of an 

offshore grid have been addressed by a variety of 

players such as the European Commission, the North 

Seas Countries’ Offshore Grid Initiative (NSC’OGI) or 

ENTSO-E. Some questions need a European approach, 

while others can be better solved at national, bilateral 

or regional level. Nevertheless, it is important to further 

clearly assign responsibilities for certain aspects 

to different selected forums and entities. 

Because the NSC’OGI brings all the relevant partners 

together, the OffshoreGrid consortium sees it as the 

ideal forum to coordinate the political, regulatory and 

market issues at international level. 

97



AcKNOWLEDGEMENTS AND FuNDiNG 

Photo: Dong Energy

Acknowledgements and Funding 

The OffshoreGrid project is funded by the European Commission (EACI) within the Energy Intelligent – Europe 

Programme. 

In addition to the principal funding by EACI and the consortium partners, the study was co-funded by ABB, Nexans, 

RWE Innogy, Amprion, Siemens, Vattenfall, the German Federal Ministry of Economics and technology and the 

Belgian Federal Public Service for Economy, SMEs, Self-employed and Energy. 

The authors further wish to thank the members of the OffshoreGrid Stakeholder Advisory Board (as listed in 

chapter 1.4) and the participants of the two Northern European and Mediterranean Stakeholder Workshops 

for their constructive criticism and suggestions regarding methodology and interpretation of results. During 

the stakeholder workshops the following stakeholders were involved: ABB sa, AC Renewables, Acciona, AEE - 

Spanish Wind Energy Association, AES Tech Ltd, Belgian government, Bloomberg, BNetzA, CNI sa, CRES, Danish 

Wind Owners Association, DESMIE, Dong Energy, DTU, ECN, Ecole des Mines de Paris, EDORA, Elia, EMEU sa, 

ENBW Erneuerbare Energien, Enercon, Energinet, ENET sa, EON Climate & Renewables, Eurec Master, European 

Commission, FCM, Fraunhofer IWES, German Government, Green Evolution sa, Hellenic Cables, Hellenic Navy, 

Hellenic Wind Energy Association, Helleniki Technodomiki Anemos sa, Helleniki Technodomiki Energiaki, Iberdrola 

Engineering and Construction, IEEE, Irish Government, KAOL Energy, Lyse, Mainstream Renewable Power, Master 

D. Hellas, Mediascape Ltd, Metron Navitas, Mytilineos sa, National Offshore Wind Energy Association of Ireland, 

Netherlands Government, Nexans, Norwegian Government, OFGEM, OWEMES Association, Power India Magazine, 

PPC Renewables, Rokas Renewables, RTE, RWE Innogy, Siemens, Speed sa development consultant, Spok consultancy, 

Statoil Hydro, Stattnet, Strenecon and associates, Syndicat des energies renouvelables, Terna Energy 

SA, United Kingdom Government, Vattenfall, VDMA, Venergia sa, Vestas, VIP Swedish Wind Energy Association, 

Voreas Energy Consultancy, VWEA, WPD, wre hellas sa, WWF Greece 


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Photo: Vestas

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Annex A – ScenArio detAilS 

Photo: Vestas

Annex A – Scenario details 

A.I Offshore wind power 

Scenarios 

An important task in the OffshoreGrid project was the 

development of offshore wind power scenarios. They 

are mainly based on the latest EWEA offshore wind 

farms scenario [20] and on the onshore scenarios developed 

in TradeWind [24], however data have been 

verified and new records have been added according 

to the latest announcements of authorities and project 

developers. The database included 373 records (wind 

farm concepts) with a total capacity of over 180 GW 

in 15 countries (apart from Northern EU countries, 

also Norway and Russia has been considered). About 

50 GW of them are well advanced projects, where developers 

and/or investors are clear and the permitting 

procedure is ongoing. 

FiGuRe 9.1: GeOGRaphic distRibutiOn OF identiFied OFFshORe pROjects 

On the basis of collected data, medium (2020) and 

long term (2030) scenarios have been developed. The 

main assumptions were: 

• The current proactive governmental policy towards 

the wind farms will be continued and joined by 

other countries, 

• Wind farms licensed already (or well defined areas 

approved) and with advanced permitting procedure 

will be implemented before 2020, where the wind 

farms operating in 2030 will be located in already 

identified zones, 

• Innovative concepts, like far (>60 km from shore) 

and deep (>60 m water depth) offshore, will not 

significantly contribute before 2030. 

The resulting scenario is presented in figure 9.1 and 

Table 9.1. 


table 9.1: the OFFshOReGRid OFFshORe wind pOweR scenaRiO FOR 2020 and 203O, cOmpaRed tO the status OF 2010 and 

the taRGets identiFied in the nReaps published aFteR the develOpment OF the scenaRiO. 

country installed 

end 2010 

48 Belgium and Finland did not specify the onshore/offshore split in documents sent to the European Commission. 

49 This figure also covers projects in the Atlantic Ocean, not included in the OffshoreGrid scenarios. 


offshoreGrid scenario nreAP’s 

2020 estimate 48 

2020 2020-2030 2030 

Belgium 195 1,994 1,800 3,794 n/a 

Denmark 854 2,329 1,470 3,799 1,339 

Estonia 0 0 1,600 1,600 250 

Finland 26 590 2,600 3,190 n/a 

France 0 2,510 2,404 4,914 6,000 49 

Germany 92 10,249 16,304 26,553 10,000 

Ireland 25 1 055 2,725 3,780 555 

Latvia 0 0 900 900 180 

Lithuania 0 0 1,000 1,000 0 

Netherlands 247 4,622 7,500 12,122 5,178 

Norway 2 957 8,710 9,667 n/a 

Poland 0 500 4,800 5,300 500 

Russia 0 0 500 500 n/a 

Sweden 164 2,983 7,539 10,522 182 

UK 1,341 15,303 22,843 38,146 12,990 

total northern eU 2,946 42,135 73,485 115,620 

total offshoreGrid 43,093 82,695 125,787 

For offshore wind energy, the most important markets 

in the medium scenario will be UK and Germany. This 

leading group is followed by The Netherlands, France, 

Sweden and Denmark. The total installed capacity 

in Northern Europe is expected to be approximately 

42 GW in 2020 and 116 GW in 2030. Until 2020, the 

major development is expected on the North Sea (63% 

of installed capacity in medium term, mostly in UK and 

Germany). In the Baltic Sea, the massive development 

of offshore wind farms is expected after 2020. Before 

this date the majority of the Baltic Sea implementations 

will be projects already started by Germany, 

Denmark and Sweden. Between 2020 and 2030 

also Poland, Finland and the Baltic states will start 

large scale offshore wind development. In 2020 the 

majority of wind energy installed capacity will still be 

onshore in most Northern European countries, except 

for the UK and Belgium. In 2030 more than 40% of 

installed wind power capacity in Northern Europe will be 

offshore projects. In the UK, Belgium, the Netherlands, 

the Baltic States and the Scandinavian countries most 

of the wind power will operate offshore. 

The OffshoreGrid scenario was developed in the beginning 

of 2010, and was then used as a basis for 

the rest of the project. In June 2010, following the 

requirements of the directive 2009/28/EC, the member 

states delivered their National Renewable Energy 

Action Plans (NREAP’s) to the European Commission. 

For most countries, these include estimations of 

the total contribution expected from offshore wind 

energy to meet the binding 2020 targets. The member 

states projections of offshore wind capacity in 

2020 (see Table 9.1) are in good agreement with the 

OffshoreGrid medium term scenario. Especially, it is 

confirmed that the majority of offshore wind energy 

development in the next 10 years is expected to take 

place in the North Sea. However, also on Baltic Sea 

the interest in offshore wind is growing, and member 

states (i.e. Poland and Baltic states) intend to join the 

offshore wind market. In conclusion, even though the 

OffshoreGrid scenario was developed before the publication 

of the intentions of the Member States, it is a 

valid scenario to be used as a basis for this project. 

107


A.II Price scenarios 

Figure 9.2 gives an overview of the chosen commodity 

price scenarios. Lignite and hard coal prices remain 

relatively stable until 2030. Gas prices increase 

slightly. The sharpest increase in prices is expected 

for crude oil and CO 2 . 

A.II.I Fuel price scenarios 

While there are world market prices for oil, fuel costs 

differ significantly between continents, regions, and 

even neighbouring countries. The basis for these differences 

stems from variable taxation, delivery costs 

(e.g. geographical aspects), promotion and regulation 

systems or the different market designs. To estimate 

the development of fuel prices for power stations 

(coal, oil, gas) economic scenarios and outlooks have 

been analysed and evaluated. 50 

FiGuRe 9.2: cOmmOdity pRices. 

Prices (€2007/MWh) 

60 

50 

40 

30 

20 

10 

0 

For the data analysis the different fuel types can be 

divided into two groups: fuel types with and without an 

existing European market. Fuel types with an existing 

European market are nuclear fuel elements, crude oil 

(and derived products) and hard coal. For these fuel 

types the same price scenario is used for all countries 

(one European price scenario). Lignite and natural 

gas are not traded on the European market. Price 

scenarios for these fuel types are defined on a by 

country basis. The following paragraphs contain the 

findings for the different fuel types. All prices are expressed 

as real prices. The base year for all fuel price 

calculations/ scenarios is 2007. 

2010 2020 2030 

Crude oil 35,4 44,9 53,8 

Hard coal 11,1 10,7 10,1 

Lignite EU 4,2 4,2 4,2 

Gas EU 21,5 23,8 24,6 

CO 2 (€ 2007/t) 23,0 36,0 44,4 

50 These include the latest DG TREN scenarios calculated with the PRIMES model, the IEA World Energy Outlook, publications from 

the GreenNet project and scenarios proposed by different institutions (e.g. EWI/Prognos, Eurelectric). 


A.II.II European fuel price scenarios 

for nuclear fuels, crude oil and hard 

coal 

To determine the prices for nuclear fuel elements 

two scenarios were analysed: DG TREN Trends 2008 

and EWI/Prognos 2006 low price scenario. Both use 

the same prices per power station as displayed in 

Figure 9.3. In general, it can be said that due to the 

FiGuRe 9.3: nucleaR Fuel elements pRice scenaRiOs (€/mwh) 

€/MWh 

3.90 

3.85 

3.80 

3.75 

3.70 

3.65 

3.60 

3.55 

51 ms= massive scenario, ss= slight scenario, lps= low price scenario, os= oil scenario, rs= reference scenario, hg= high growth. 


2010 

FiGuRe 9.4: cRude Oil pRice scenaRiOs (€/mwh) 

€/MWh 

70 

60 

50 

40 

30 

20 

10 

0 

2007 

2020 

DG Tren Trends 2008 EWI/ Prognos 2006 (lps) 

IEA 2008 (rs) 

IEA 2007 (hg) 

IEA 2007 (rs) 

2010 

2015 

EWI/ Prognos 2006 (rs) 

EWI/ Prognos 2006 (os) 

EWI/ Prognos 2006 (lps) 

world market trade of nuclear fuels the same price can 

be used for all European countries. 

The prices of crude oil already differ significantly within 

each study analysed. Prices range from €60 per MWh 

to €25 per MWh in 2030. In most of the reviewed 

studies different price scenarios are given. To illustrate 

these variations, Figure 9.4 displays some of 

the analysed crude oil price scenarios. 51 The dena 

2020 

2025 

DG Tren 2008 

dena 2008 

BMU 2008 (ss) 

2030 

2030 

BMU 2008 (ms) 

109


2008 scenario displays the average of the two price 

paths within the BMU Leitszenario 2008 and has been 

broadly discussed and generally accepted among experts. 

For this reason it will be used as a basis for the 

price of nuclear energy in this study. 

FiGuRe 9.5: haRd cOal pRice scenaRiOs (€/mwh) 

€/MWh 

30 

25 

20 

15 

10 

5 

0 

30 

25 

20 

15 

10 

5 

0 

2007 

IEA 2008 (rs) 

IEA 2007 (hg) 

FiGuRe 9.6: cOuntRy speciFic Gas pRice scenaRiO (€/mwh) 

National speci�c gas price 

(EUR 2007/MWh) 

2010 

EU Scenario Germany 

UK 

Estonia 

Belgium 

2010 

IEA 2007 (rs) 

2015 

Bulgaria 

2015 

EWI/ Prognos 2006 (rs) 

Hard coal, in contrast to lignite, is a product that is 

traded on the world market (Figure 9.5). In some studies 

the prices are basically constant, while in others 

they rise significantly until 2030. The IEA reference 

scenario (rs) displays the average price development 

across all studies, and is therefore used for modelling. 


2020 

Latvia 

2020 

2025 

EWI/ Prognos 2006 (os) 

EWI/ Prognos 2006 (lps) 

2025 

2030 

BMU 2008 (ss) 

BMU 2008 (ms) 

2030

A.II.III National fuel price scenarios 

for gas 

Gas prices play an important role in modelling the 

European energy market because of the following 

aspects: 

• Due to the increasing share of fluctuating renewable 

energy, gas power plants will be operated more 

frequently and therefore set the price of the merit 

order 52 with rising probability. 

• In contrast to nuclear fuel and hard coal, gas prices 

differ largely between countries. 

Thus, variable gas prices are one of the most important 

factors that determine country-specific energy 

generation costs. In order to model the European 

energy market, country-specific gas price paths were 

developed. 

FiGuRe 9.7: cO 2 pRice scenaRiOs 

CO 2 price 

(€2007/tonne CO 2 ) 

70 

60 

50 

40 

30 

20 

10 

0 

52 The merit order represents the supply curve of electricity generation. The generation units are ranked according to their marginal 

production price. Wind energy for instance has zero marginal production costs and is therefore one of the first units chosen for 

meet electricity demand. 

53 See Verein der Kohleimporteure: Annual Report 2009; EUROSTAT: Key figures on Europe 2009 edition; EWI, EEFA: 

Energiewirtschaftliches Gesamtkonzept 2030, 2009 

54 In the long-term both the variable and fixed costs must be recovered. 


BMU 2007 (low) 

BMU 2007 (slight) 

BMU 2007 (massive) 

BMU 2008 (slight) 

BMU 2008 (average) 

BMU 2008 (massive increase) [2] 

The results are illustrated in Figure 9.6. Gas prices 

differ strongly in 2010 and tend to harmonise towards 

2030. In Germany and UK, prices are the highest (due 

to high gas prices for industrial consumers). 

A.II.IV National fuel price scenarios 

for lignite coal 

Due to the high transport costs (relatively low amount 

of energy per weight unit), lignite is not traded on 

national or international markets. Thus, there is no 

market price for lignite coal. This means that for all 

European countries in which lignite is produced, nearly 

the same amount which is extracted is also consumed 

for energy production. 53 Furthermore in most countries 

geological extraction and electricity production from 

lignite are conducted by the same company. The company 

will operate the lignite power plant as long as the 

variable costs are covered. 54 Hence, for modelling the 

merit order, the variable lignite extraction costs must 

be used instead of the price. 

2010 2015 2020 2025 2030 

dena 2008 

DB 2008 

ECX EUA Futures 

ECX EUA Futures (2009) 

ECX EUA Futures (2008) 

111


Due to the lack of public available cost data the merit 

order of lignite electricity production was calculated 

with the variable costs of extraction which equate to 

about 1/3 of the lignite price (scenarios). 55 

From interviews and studies the lignite price for five 

countries could be gathered (see Table 9.2). The lignite 

production in these countries accounts for more than 

2/3 of the European lignite production and consumption. 

For the modelling process the country specific 

lignite prices were taken where available. For all other 

countries a European price scenario was developed. 56 

table 9.2: speciFic liGnite pRices [€/mwh] 57 

lignite Price [€/MWh] 2010, 2020, 2030 

Albania 5.08 

Germany 4.20 

Greece 4.40 

Kosovo 4.18 

Poland 4.69 

Price for rest of Europe 4.20 

A.II.V CO 2 Price Scenarios 

In 2005, CO 2 certificates were introduced in Europe 

via the implementation of EU ETS. The CO 2 price is 

an additional cost element for the use of fossil fuels. 

To estimate the price development of CO 2 certificates 

several studies have been reviewed. Furthermore, the 

trading prices for EU emission allowance (EUA) futures 

were analysed. 

Figure 9.7 illustrates the different CO 2 price scenarios. 

The analysed scenarios differ widely. The diversity 

reflects the different assumptions for the oil price 

development. 58 The BMU 2008 average scenario has 

been validated by several experts and was chosen for 

modelling. 

Secondly, it is evident, that the ECX EUA Future prices 

were located in between of the analysed price scenarios. 

The market participants did not share the 

expectation of sharp price increases due to future CO 2 

certificate shortages. 

55 dena 2008; EWI, EEFA: Energiewirtschaftliches Gesamtkonzept 2030, 2009; Various telephone interviews with Jochen, Schwill, 

EWIS, October 2009. 

56 Based on Ewi/ Prognos 2006 low price scenario. 

57 dena 2008; Janusz Bojczuk, Poltegor Engineering, October 2009; Employer’s Confederation of the Polish Lignite Industry, 2009; 

Marios Leonardos, Mines Planning & Performance Department. 

58 Increasing oil prices lead to high gas prices and comparatively low coal prices. Low coal prices indicate higher demand for coal, 

and therefore rising CO2 prices. 


Annex B – technoloGy ASSUMPtionS 

Photo: Vestas

Annex B –technology Assumptions 

B.I Offshore technology 

assumptions 

The 326 offshore wind power projects that fall within 

the geographic sphere of the OffshoreGrid project 

have a capacity range from as little as 5 MW to a 

maximum of 2,000 MW and have interconnection 

route distances between 1 km and 434 km. In this 

study, the total offshore wind capacity considered for 

the in Northern Europe scenario is 126 GW. 

Obviously, to connect such a wide range of capacities 

over quite various distances will require different 

transmission technology solutions. It is the purpose of 

this section to briefly explain why certain transmission 

technologies have been selected for specific connections 

and also define what design building blocks have 

been used to build up the offshore power grid from the 

individual offshore substations through to the onshore 

connection points into the existing onshore transmission 

network. 

B.I.I Offshore wind farm 

substations and platforms 

The traditional voltage for connecting offshore wind 

turbines to the MV wind farm power collection system 

is up to 36 kV. However, due to the power capacities 

accumulated in many of the offshore wind farms considered 

in OffshoreGrid and the distance from shore it 

is not possible for the power to be transmitted to the 

onshore grid at this voltage for most of the projects. 

Hence, offshore substations will need to be established 

for many of the projects to accumulate the 

power from the internal wind farm cable array and step 

up the voltage to a level appropriate for transmission 

over distance. 

The amount of power that can be accumulated at 

one offshore substation, and hence the number of 

offshore substations required for each wind farm, 

will be dictated by the power carrying capacity of the 

onward transmission medium, the power carrying 

capacity of the array cabling, and the number of 

wind turbines. The distance from the platform to the 

furthest wind turbine in the array must also be taken 

into consideration, as using excessive lengths of 36 

kV cable to connect an array can lead to excessive 

power losses. Export cables then connect the offshore 

substation platforms (generally HVAC) either directly 

to the onshore grid or to HVDC converter platforms 

depending on the capacity and distance to shore. 

Offshore platforms are required to house the 

substations which gather wind turbine connection 

cables and step up the voltage for transmission to 

shore. Platform topsides are supported on jackets 

(with anything from 3 to 8 legs) piled into the seabed. 

Monopiles can be used for smaller platforms, whereas 

self installing floating platforms are going to be used 

in the future due to the shortage of installation 

vessels and cranes. In addition to housing 

transformers, cooling radiators, fans, switchgears, 

and the associated control panels, the platform will 

typically include emergency accommodation and 

life-saving equipment, a crane for maintenance lifts, 

a winch to hoist the subsea cables, backup diesel 

generator, fuel, helipad, communication systems, 

and the means to support J-tubes which contain the 

subsea cables. 

B.I.II Available transmission 

technologies 

There are various transmission technologies for offshore 

wind farms available. In the following section 

the chosen technologies for the OffshoreGrid project 

are briefly reviewed. 

High voltage alternating current (HVAC) 

solutions 

The advantage of using AC cables as a connection 

medium is obvious when the requirement is to link an 

offshore farm or farms which are generating at AC with 

an onshore network that is supplying AC. However, the 

capabilities and limitations of AC cables are also well 

known, especially when connecting long distances. 

Due to needed reactive compensation, AC subsea 

cables have only been considered as a possible 

connection technology in this study where the total 

cable route length is less than 80km. 

AC cables come in many types with variations possible 

on the metal used for the conductors (Copper 

or Aluminium), the type of insulation (oil mass impregnated 

(MI) paper or extruded cross linked polyethylene 

(XLPE)), and the type and need for armouring. These 


factors combined with the voltage and ampacity dictate 

the power carrying capabilities of a cable and 

ultimately its cross sectional area. The choice of 

which type of cable to use is very much project specific 

and depends on a whole host of economic and 

environmental factors, such as capital cost, losses, 

and the thermal resistivity of the medium in which the 

cable will be laid. Within the OffshoreGrid project the 

following offshore AC cable maximum size building 

blocks are regarded (Table 10.1). The infrastructure 

cost model selects cable sizes up to the cross sectional 

area shown below [27]. 

High voltage direct current (HVDC) solutions 

In a HVDC system, electric power is taken from one 

point in a three-phase AC network, converted into DC 


by a converter station, transmitted to the receiving 

point by an overhead line or underground / subsea 

cable and then converted back into AC by another 

converter station and injected into the receiving AC 

network (Figure 10.1). 

Traditionally, HVDC transmission systems are used 

for transmission of bulk power over long distances. 

The technology becomes economically attractive 

compared with conventional AC lines as the relatively 

high fixed costs of the HVDC converter stations are 

outweighed by the reduced losses and reduced cable 

requirements. 

The following HVDC converter capacities (Table 10.2) 

will be used within the OffshoreGrid design. 

FiGuRe 10.1: OveRview OF vsc hvdc tRansmissiOn FOR OFFshORe wind FaRms; imaGe cOuRtesy OF abb 

table 10.1 OFFshORe and OFFshORe ac cable desiGn ‘laRGest buildinG blOcks’ 

nominal 

Voltage 

(kV) 

cores conductor insulation Available Pre 2020 c.s.a (mm 2) 

Power rating 

(MVA) 

Offshore Onshore Offshore Onshore Offshore Onshore 

33 3 Copper XLPE Yes Yes 1,200 2,000 52 65 



220 3 Copper XLPE Yes Yes 1,200 2,000 347.5 431 

400 3 Copper XLPE Yes No 800 2,000 491.7 739 

table 10.2 hvdc cOnveRteR desiGn ‘buildinG blOcks’ 

type Voltage (kV) configuration Available Pre 2020 Power range (MW) 

VSC +/-150 Symmetrical monopole YES Up to 500 

VSC +/-320 Symmetrical monopole YES Up to 1,200 

VSC +/-500 Symmetrical monopole /Bipole NO Up to 2,000 

CSC +/-250 Bipole YES Up to 1,000 

CSC +/-500 Bipole YES Up to 2,000 

VSC +/-150 Symmetrical monopole YES Up to 500 

115

Annex B –technology Assumptions 

table 10.3 OFFshORe dc cable desiGn ‘buildinG blOcks’ 

nominal Voltage 

(kV) 

conductor insulation 

Available pre 

2020 

c.s.a (mm2 ) 

Max Sending 

Power (MVA) 

150 Copper XLPE YES 2,500 600 

320 Copper XLPE YES 2,500 1,280 

500 Copper XLPE NO 2,500 2,000 

500 Copper MI YES 3,000 2,000 

HVDC cables 

In order to reach the levels of power transfer required 

for the 2020 and 2030 OffshoreGrid designs, cables 

that can operate at high voltages will be required. As a 

result of conversations with cable manufacturers, the 

following DC cables in Table 10.3 have been specified 

within the OffshoreGrid design. 

Superconductors 

Superconductors are able to transfer large amounts 

of power using low voltages without the high 

electrical losses that are normally experienced 

using traditional conductors. However to maintain 

their superconducting state, they must be kept very 

cold and thus require cooling stations to be located 

approximately every 2km along the length of the 

cable. This is not practical for offshore applications 

as the cost of the cooling stations would outweigh 

any advantage gained from the superconducting 

cables. For this reason, superconductors have not 

been considered as a transmission technology for the 

modelling in OffshoreGrid. 

Gas insulated transmission lines 

Gas Insulated Lines (GIL) are a 3 phase AC transmission 

technology available up to 400 kV and 3000 MW. 

They are able to transfer large amounts of power over 

greater distances than AC cables because they use 

SF6 gas as the insulating medium between the live 

conductors and earth instead of XLPE. As a result the 

GIL has a lower capacitance meaning longer distances 

may be connected before the real power transfer 

capacity becomes limited by the charging current associated 

with AC transmission. 

GIL has been installed onshore in transmission systems 

and is directly buried in the ground. For subsea 

applications the GIL must be installed in a pipeline to 

provide physical protection. GIL has been considered 

in the OffshoreGrid design, however due to the high 

costs of building and installing the GIL in subsea pipelines 

it remains more expensive than the alternative 

HVDC solution and has therefore not been used for 

any of the designs. 

B.I.III Switchgears 

Within the Offshore Grid design building blocks HVAC 

Gas Insulated Switchgears (GIS), HVAC Air Insulated 

Switchgears (AIS) and HVDC Switchgears have been 

considered. GIS has been found to have numerous 

advantages compared to AIS. HVDC switchgear, with 

the exception of circuit breakers, is similar to existing 

AC switchgear and may use either AIS or GIS design. 

The methodology used in the offshore grid designs 

has been to use DC fault isolation equipment (such 

as DC circuit breakers) to prevent any power infeed 

loss to onshore AC transmission systems exceeding 

the amount of frequency control reserve held by the 

onshore system. 


title Annex c – detAilS on MethodoloGy And ModelS 

Photo: Stiftung Offshore Windenergie - Detlev Gehring

Annex c – details on Methodology and Models 

The OffshoreGrid results are based on detailed 

generation modelling, market and grid power flow 

modelling and infrastructure cost modelling. Each 

of the aforementioned modelling tasks is already a 

great challenge on its own and there is no integrated 

end model that could solve the envisaged optimisation 

goal to determine an optimal offshore grid. The 

consortium therefore set up a stepwise methodology 

in which different models are combined in an iterative 

approach, as shown in Figure 12.1. All in all four major 

models were developed and applied: 

1. Wind power time series model 

Because of the predominant impact of wind power infeed 

on the optimal grid design, special efforts have 

been made to generate appropriate wind power time 

series. A specialised wind power model (meso-scale 

numerical weather prediction model) has been used 

for this purpose. The resulting wind power time series 

are used as input to the power market and flow model 

described below. 

FiGuRe 12.1: scheme OF mOdels 


cost model 

Data collection and scenario development 

Power market and 

power flow model 

• Cost benefit results for different offshore grid building blocks 

• Fundamental design guidelines 

• Cost efficient overall grid design 

2. Power market and power flow model 

Power plants generate when they can sell their electricity 

to the market if there is enough grid capacity to 

transport it. The power market and power flow model 

simulates the operation of the power system based 

on a detailed set of European generation data (capacity, 

costs etc.) and a detailed European grid model. 

Both conventional power plants and RES generation 

is modelled. 

3. Infrastructure cost model 

To build offshore grid infrastructure requires large investments. 

The extent of these investments is a key 

figure to be considered when determining the overall 

costs and benefits of the considered design. The infrastructure 

model takes into account costs of different 

offshore cable and equipment technology, the cable 

length, sea depth, bathymetric data etc. 

wind series 

power model 

case-independant 

model 


4. Case-independent model 

During the course of the study it became apparent that 

the appropriate wind farm connection design is very 

sensitive to the specific cases under investigation: 

distances to shore, wind farm capacities, price profile 

differences between the countries, etc. The results of 

the specific cases are useful but general conclusions 

are necessary for the optimal offshore grid design and 

also for clear recommendations, which is one central 

goals of the OffshoreGrid study. A case-independent 

model was therefore developed with inputs from the 

infrastructure model and the power system model. It 

allows developing general offshore grid design rules, 

which are then validated with the results of the specific 

cases of the model. 

In the following sections, the key features of each of 

the mentioned models are described. 

C.I Wind power time series 

model 

Since on- and offshore wind power production is a crucial 

element in designing an offshore grid, OffshoreGrid 

builds on high-resolution time series of wind speed 

and power output of onshore- and offshore wind farms 

which served as input for the modelling power flows 

and power markets. For all single offshore wind farm 

locations of the input scenario, synchronous hourly 

time series of historical wind speed were calculated 

with a high-resolution weather model. These are then 

transformed into wind power production time series by 

using special power curves. 

The applied Weather Research and Forecasting Model 

WRF [1] is a meso-scale numerical weather prediction 

model, able to simulate the atmospheric conditions 

across a wide range of horizontal resolutions from 

100 km down to 1 km. The data input for WRF is 

provided by 6-hourly global weather analysis data 59 . 

The WRF-simulations dynamically downscale the 

weather analysis data from six-hourly resolution on 

a horizontal grid of 1° by 1° to one-hourly data on a 

9x9 km² grid 60 . 

59 In this case: FNL Final Analysis from the United States’ National Centre for Environmental Prediction (NCEP). 

60 In geographical coordinates, 1° corresponds approximately to 50-111 km. 


FiGuRe 12.2: GeOGRaphical dOmains FOR the wRFsimulatiOn 

as used in the OFFshOReGRid pROject 

The region of the Northern European waters is 

modelled with a higher spatial resolution than the 

remainder of Europe (see Figure 12.2): 

• Europe north of the Alps: 9 x 9 km² (including 

offshore regions in focus) 

• Europe south of latitude 48°N: 27 x 27 km² 

The wind speed time series were calculated for all 

relevant hub heights of turbines in today’s and future 

offshore and onshore wind farms. Special attention 

was paid to the vertical wind speed profiles in different 

thermal stratifications of the local atmospheric flow, 

which were modelled with an improved, so called 

MYJ-Scheme for the atmospheric Planetary Boundary 

Layer (PBL) [7]. The model output is validated 

with real wind speed data at different heights, i.e. 

measurements from the German offshore platform 

FINO-1 [6]. Previous simulations with similar model 

settings were also checked with other meteorological 

observations, e.g. the met mast Östergarnsholm in 

the Baltic Sea. The model proved to be accurate and 

robust. 

After the WRF model runs were performed and 

validated, the wind speed time series at more than 

350 offshore sites and 16,000 onshore grid points as 

defined in the scenarios and models were determined. 

119

Annex c – details on the Methodology and Models 

The wind speed time series were transformed to wind 

power with different types of power curve models for 

both onshore and offshore wind farms: 

• For the identified offshore wind farms, aggregated 

wind farm power curves were derived by applying 

wind farm wake effects 61 to Multi-Mega-Watt power 

curves of future offshore turbines [9][10][11]. 

• In order to calculate the regional onshore power 

time series, the refined power curve model 

developed in the TradeWind project [2] is applied. 

The time series reflect many relevant meteorological 

events, such as movements of storm fronts across 

large areas or large-scale calms. The dataset enables 

the evaluation of the implications of such events on 

the output of wind farms across a region, countrywide 

and for large offshore areas. 

More information on this model can be found in the 

deliverable 3.2b [25]. 

FiGuRe 12.3: OFFshOReGRid zOnes in the euROpean GRid mOdel FOR the hub base case 2030 

61 The wind that passes a wind turbine rotor is heavily impacted by the rotational force of the rotor. The area of influenced wind is 

called the wake of the wind turbine. When there are other wind turbines in this wake, their output is reduced. This is called the 

wake effect. The modelling of these effects is an important field of research. 


C.II Power market and flow 

model 

The power market and power flow model simulates the 

operation of the power system based on a detailed set 

of European generation data (capacity, costs etc.) and 

a detailed European grid model. This allows the assessment 

of system operation costs, and the possible 

benefits by e.g. installing an extra interconnector. 

The model used for the flow-based power market simulations 

is a Matlab-based collection of classes and 

functions referred to as the SINTEF Power System 

Simulation Tool (PSST) [2]. It is an updated version of 

the model used by SINTEF in the IEE project TradeWind. 

PSST combines a market model with a model of the 

European electricity grid. The model assumes a perfect 

market with nodal pricing. The socio-economic 

FiGuRe 12.4: Gis cable ROutinG 


optimum for the overall European electricity production 

is found by minimising the total yearly generation 

cost. From the simulations both technical and economic 

parameters, such as generation cost, energy 

prices, price differences and grid utilisation (off- and 

on-shore) for different scenarios can be extracted. 

The optimal generation dispatch is computed on hourly 

basis and the power flow through the electricity grid 

is linearly approximated (DC power flow [12][13]). In 

more technical terms, the optimal solution for each 

hour is found by minimising a cost function that essentially 

expresses the cost of generation, with different 

marginal generation costs for different countries and 

generator types. The power flow is constrained by the 

grid capacity on individual branch level and on international 

interconnections. This is fed as mathematical 

constraint into the optimisation problem. 

121


A detailed European grid model including the countries 

in Eastern Europe and power exchange capacities with 

Russia is the fundamental input for the power flow 

calculations. The inputs to the program are the grid 

model, the generation capacity forecast and cost for 

all generator types per country, hydro reservoir levels, 

and time series for demand, wind power production 

and hydro inflow. 

For each hour the program updates the demand, wind 

production and marginal cost of hydro units based on 

reservoir levels, and runs an optimal power flow which 

determines the power output of all generators and on 

all lines. PSST keeps track of the reservoir level for hydro 

units by calculating the inflow and hydro production 

given by the hourly solution of the marked model. The 

power output of the generators is dependent on the 

minimum and maximum capacity, the marginal cost 

relative to other generators as well as the limitations 

of power flow on lines capacity and the impedances. 

The European grid model used in this project is divided 

into five synchronous regions: Continental Europe 

(former UCTE), Great Britain, Ireland, the Nordic region 

(former Nordel) and the Baltic region. The countries 

included in the model are shown in Figure 12.3. The 

zones within the countries are indicated by white dots, 

interconnections are given as blue lines. As can be 

seen, France is modelled as 4 zones, while Germany 

is modelled as 6 zones. 

By adding the network grid as constraints to the market 

model the effect of network constraints on both prices 

and bottlenecks is identified. Not only will it identify 

production and consumption but also the utilisation 

of individual branch and HVDC connections, showing 

where power flows through the system, identifying 

bottlenecks and main power transfer corridors. The results 

from the market model optimisation are given on 

a detailed level for individual branches and nodes, but 

it is also aggregated to area/zone totals to ease the 

analysis of the results for such a large model. 

The total cost which is a direct output of the market 

model, is a good parameter for evaluating the benefit 

of introducing new capacities into the electrical power 

system 62 , while the price difference between parts 

of the system is an indication of where to introduce 

such new capacities. In order to indentify the need for 

interconnectors between countries price differences 

between areas are required. However, the model 

will produce nodal prices which reflect the marginal 

cost of supplying power to a given node. The nodal 

prices are a good basis for computing the area price, 

i.e. the wholesale consumer price for power within a 

geographic area. Such areas are typically countries or 

zones within a country. Area prices in the PSST are 

computed from nodal prices as a weighted average, 

with weights given as the relative demand within the 

area. That is, the nodal prices at heavy load nodes are 

more important than the nodal prices at nodes with 

light load. In this way the model is able to find area 

prices, while still including the electricity network and 

having the high degree of freedom given by the nodal 

price model. 

When comparing the infrastructure costs to the system 

benefits for two different design options, the system benefits 

are calculated as the present value of the difference 

in total cost between both cases over a lifetime of 25 

years, and calculated with a discount factor of 6%. 

More information on the market and grid model can be 

found in Deliverable D6.1 and D6.2 [29]. 

62 Doing the analysis via the total system costs means that the optimisation is done from European welfare point of view. 


C.III Infrastructure cost model 

The infrastructure costing model is used to determine 

the capital costing of the entire OffshoreGrid infrastructure 

used in the modelling phases, including: 

• Individual wind farm connections 

• Hub connections of wind farms 

• Wind farm Tee-in connections 

• Direct interconnectors 

• Meshed hub-to-hub, hub-to-shore interconnectors 

• Split wind farm connections 

The infrastructure cost model feeds directly into the 

net benefit model, together with the results from the 

power market model to assess the viability of links 

for arbitrage. The infrastructure cost model has two 

main stages, firstly incorporating a technical assessment 

of the required infrastructure to determine the 

required technology and then a costing exercise is performed 

to produce the capital costing for each wind 

farm connection. 

table 12.2: eneRGy pRice diFFeRences as deteRmined by pOweR maRket mOdel 


table 12.1: inteRcOnnectOR utilisatiOn between 2008 

and 2010 [41] 

interconnector Utilisation 

GB – France 60.3% 

Moyle 55.9% 

NorNed 74.9% 

Average 63.7% 

C.III.I Design assumptions 

Offshore generation (GIS) locations 

In order for the model to produce accurate costing 

the lengths of cable routes must be determined accurately. 

Initially all of the offshore projects and onshore 

connections points derived in WP3 were plotted in GIS 

software along with subsea obstacle data obtained 

from European oceanographic societies and governments. 

This allows accurate cable routes to be plotted 

to the projects around any subsea exclusion zones, 

(Figure 12.4) with distances for both onshore and offshore 

cable routes with the number of obstacles to 

be crossed. 

Technology 

The costs produced by the infrastructure cost model 

are determined mainly by what technology is required 

and the connection distance. Following the calculation 

of the route lengths a technical assessment is 

made to determine the topology for each link. For wind 

Be de dK ee Fi Fr GB ie lt lV nl no Pl Se 

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Fi 23.72 22.05 16.21 18.80 16.48 20.30 23.36 18.95 18.80 20.70 9.90 20.92 7.29 

Fr 10.12 9.46 7.55 8.49 16.48 8.85 11.31 8.53 8.49 8.34 10.64 9.55 17.21 

GB 9.42 8.82 8.92 10.01 20.30 8.85 6.06 9.89 10.01 6.46 15.04 10.04 21.16 

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lt 6.92 5.37 5.83 1.24 18.95 8.53 9.89 10.60 1.24 7.75 13.39 2.75 20.53 

lV 6.38 5.41 6.20 0.00 18.80 8.49 10.01 10.42 1.24 8.12 13.44 3.72 21.13 

nl 7.00 5.28 6.28 8.12 20.70 8.34 6.46 8.60 7.75 8.12 14.66 7.21 21.21 

no 17.46 15.70 10.11 13.44 9.90 10.64 15.04 18.08 13.39 13.44 14.66 14.80 8.82 

Pl 6.03 4.43 6.88 3.72 20.92 9.55 10.04 10.18 2.75 3.72 7.21 14.80 22.13 

Se 25.89 23.99 17.04 21.13 7.29 17.21 21.16 24.80 20.53 21.13 21.21 8.82 22.13 

123


farm connections and hub connections this could be 

either AC or DC depending upon the distance. All interconnectors 

for arbitrage have been assumed to be 

DC due to the distances involved in connection. The 

technology available is based on what technology is 

commercially available today and future technology 

established in section B.I. 

Inputs to infrastructure cost model 

The following parameters are used as inputs to the 

infrastructure cost model when assessing wind farm 

and hub connections: 

• Connection distance (onshore / offshore) 

• Project timing (pre / post 2020) 

• Capacity (MW) 

• Onshore network security criteria 

Connection distance is used in the infrastructure cost 

model to determine the power transfer capability of AC 

and DC cables over the given distance. For DC cables 

the resistance creates a voltage drop which means 

the receiving power of the cables is less than the 

sending power. The voltage drop is reduced by selecting 

cables with larger and more expensive conductor 

sizes. If the losses are excessive then the cable is not 

used and the model selects a larger cable. AC cables 

have a technical limitation on the distance they can be 

used due to the charging current they generate. The infrastructure 

cost model calculates the power transfer 

capability of the AC cables in order to determine how 

many are required at each voltage level to transfer the 

power to shore if indeed it is possible to use an AC 

connection at all. 

Project timing is used to determine the technology 

used on the project. Any wind farms built pre 2020 

are limited to technology commercially available today 

with post 2020 projects allowed to use technology 

with increased capacities as defined in Section B.I. 

Project capacity and network security criteria are used 

to determine the maximum capacity offshore link which 

can be connected to an onshore connection point. All 

links terminating to onshore connection points cannot 

exceed the current or future planned network security 

criteria. This limits the maximum amount of power 

which can be transferred over a single link due to the 

amount of reserve held by the onshore network to cater 

for an in-feed loss to the system. If the offshore 

grid link or project size exceeds the network security 

criteria then the link must be split into multiple smaller 

links or DC circuit breakers used to segregate the 

offshore grid network so for any fault or outage of cables 

or converters then the onshore network security 

criteria is not exceeded. This has an impact on cost, 

as potentially more equipment is required to achieve 

the same power transfer compared to larger onshore 

networks where larger in-feed losses can be handled. 

C.III.II Costing process 

The costing process assesses each AC and DC cable 

voltage in turn to determine the size, number and cost 

of cables required for the given distance and capacity. 

Following this the number of DC converters & switchgear 

is determined based on the number of cables, 

project size and network security criteria. 

When costing wind farm projects or hubs the model 

selects the cheapest option whether it is AC or DC 

and outputs: 

• Capital costing 

• Technology 

• Cable sizes 

• Quantity of key plant (converters, offshore 

platforms) 

When assessing interconnectors, such as direct interconnectors 

between onshore connection points or 

interconnectors between hubs the model defaults to 

DC as the technology choice and outputs the capital 

costing. Further information on the costing process 

can be found in deliverable D5.2 – OffshoreGrid 

Design Proposals Report [27]. 

C.III.III Direct interconnector 

justification formula 

To assess the viability of direct interconnectors within 

Northern Europe a justification formula was used. This 

formula is used to identify direct interconnectors to 

study based on their estimated profitability. Following 


identification, the power market model was used with 

the identified potential direct interconnectors in order 

to produce the total generation costs, which in 

turn was then used to assess the net benefit of the 

interconnectors. 

The power market model was used to initially create 

a reference case of energy price differences between 

the countries around the North and Baltic Seas. An 

example of the price differences is shown in Table 16. 

These price differences were based on the scenario 

with all offshore generation built using either individual 

or hub connections, and all of the planned interconnectors 

in the ENTSO-E TYNDP. The price differences 

are used to determine the potential interconnector 

revenue based on the following assumptions: 

• 25 year payback period 

• Interconnector utilisation of 63.7% 

• 1,000 MW building blocks for each interconnector 

• Interconnector receiving 60 - 100% revenue from 

the price differences 

The interconnector utilisation figure was derived 

from the average utilisation of the England France 

(2,000 MW), Moyle (Scotland – Northern Ireland, 

500 MW) and NorNed (700 MW) interconnectors 

using data downloaded from the ENTSO-E website 

from 2008 to 2010. 

Interconnectors generate revenue by trading their capacity 

with energy suppliers and this is usually done 

through an auction process consisting of long and 

short term contracts. The interconnector is relying on 

the price differential between two countries or markets 

so that a supplier will buy energy outside of their domestic 

market and use the interconnector to transfer 

it. The supplier is looking to be able to buy energy and 

use the interconnector for a lower cost than buying it 

within their domestic market. To this end suppliers set 

up long term contracts with interconnectors and typically 

the interconnector will receive 60% of the price 

difference as revenue. This rises up to 100% of the 

price difference in short term contracts where energy 

suppliers choose to buy from foreign markets in order 

to meet their supply requirements. 


Based on the price difference between all of the 

European countries around the North and Baltic Seas 

and the above parameters, the potential revenue of 

interconnectors was calculated between all countries 

which can be connected geographically. The capital 

cost of 1,000 MW interconnectors was also produced 

and to compare against the revenue to produce the 

profitability of all potential direct interconnectors. 

Ranking the profitability and selecting the 10 most 

profitable links initially produced the first 10 interconnectors 

to study in the power market model. 

Following identification using the above described 

process the power market model was run with each 

interconnector added in turn to produce the total 

generation cost for the European system. Total 

generation cost and the capital costs of the extra 

infrastructure is then assessed to determine the net 

benefit, where if the total generation cost is reduced 

by more than the capital cost of the assets over their 

lifetime then the link is beneficial and kept in the 

model. Any links that were not beneficial were removed 

from the model. The process of adding links has the 

effect of reducing the total generation costs and also 

reducing the price differences between countries. 

Therefore an iterative process was performed where 

the updated price differences were used again in order 

to identify more interconnectors to study in the power 

market model until the price differences were lowed 

sufficiently so there is no more net benefit of adding 

direct interconnectors. 

C.IV Case-independent model 

The results of the combined power system and infrastructure 

models yield good insights in the design 

drivers for the specific cases investigated. As the results 

have proven to be very case-dependent, it was 

difficult to draw general conclusions which are useful 

for the European Commission, Transmission System 

Operators, and project developers. Moreover, such 

conclusions were needed as guidelines in the iteration 

process towards an overall offshore grid design. 

125


The consortium has therefore decided to develop a 

case-independent model, which is an abstract model 

that can help to do extensive sensitivity analysis in 

an efficient manner. The results are cross-checked 

with the case study results from the real model. The 

case-independent model uses inputs from both the 

infrastructure and power system model. Instead of doing 

an optimisation process for each hour of the year, 

it aims at approaching the cost-benefit results based 

on average values and with simple straightforward 

rules. Consequently, it provides an approximate but 

robust result that allows quickly assessing whether it 

is worth to investigate the case in more detail. 

As with the combination of the models of section 

C.II and C.III, the costs and benefits are compared 

for different designs, where costs and benefits are 

defined as: 

• Infrastructure costs (depending on cable length 

and capacity) 

• System benefits = present value of yearly trade 

benefits, which are defined as the sum of the product 

of hourly price difference between countries 

and the hourly remaining capacity for trade (interconnector 

capacity not used by wind power) 

The model is built in Matlab and focuses on two design 

problems, namely the teeing-in of wind farms into 

an interconnector between two countries, and the interconnection 

of two countries via two offshore wind 

farm hubs in between. As inputs, it uses: 

• Infrastructure cost tables (varying with distance 

and capacity) developed by SEL for: 

– individual connection of wind farms 

– teeing-in of wind farms 

– direct interconnector 

– interconnector between hubs 

• Market price profiles and the difference between 

them for different countries (outcome of the power 

system model by SINTEF) 

• Time series for the wind power production of a wind 

farm (data from Forwind model used) 

126 

The objective of the case-independent model is to 

have concrete design guidelines that are useful for 

various stakeholders. To this end, an extensive sensitivity 

analysis is done that looks into the impact of the 

price difference between countries, to the impact of 

cable or wind farm capacities, to the impact of cable 

lengths and reduced cable length, and to the direction 

of the price difference. The model can vary the following 

parameters: 

• Average absolute price difference between 

countries 

• Balance of the price difference between countries 

(balanced flow with 50% of price difference to either 

country or balanced more towards one of the two 

countries) 

• Distance between onshore connection points 

(cable length direct interconnector) 

• Distance between hubs and onshore connection 

points 

• Distance between hubs (possible reduction in cable 

length vs. a direct interconnector) 

• Capacity of the wind farm(s) 

• Capacity of the cables 

OffshoreGrid – Final Report

Annex d – detAilS oF reSUltS 

Photo: Detlev Gehring - 

Stiftung Offshore Windenergie

Annex d – details of results 

D.I Wind output statistics 

D.I.I Spatial smoothing of 

wind power 

There are several techno-economic benefits directly 

linked to an offshore grid as outlined in the introduction. 

One of these benefits is the additional 

interconnection of wind energy generation centres 

across Europe which smoothes the wind energy variability 

towards a more steady generation profile. This 

issue was already studied by the TradeWind study and 

was further elaborated within OffshoreGrid as more 

accurate wind power time series were available. 

This smoothing effect is illustrated in Figure 13.1, 

displaying the gradients for three different sizes of 

regions in Denmark (a gradient is the percentage by 

which power goes up or down in one hour, or % fluctuation 

in an hour). It can clearly be seen that the 

gradient, or fluctuation in wind power, is much less 

when looking at a large region such as the whole of 

Denmark, when compared to the gradient of just one 

wind farm. 

The effect is even more pronounced when aggregating 

on a European level, as shown in Figure 13.2. 

Whereas offshore EU wind power still exhibits hourly 

gradients of 8% during a noticeable time per year, total 

EU wind power (onshore plus offshore) hardly shows 

hourly gradients in excess of 5%. 

The smoothing effect on wind variability is clearly visible 

in Figure 13.3 where it is clearly shown that the 

wind power generation of the OffshoreGrid 2030 scenario 

across a large area as EU27 (incl. Norway and 

Switzerland) exhibits a significantly lower variability 

compared to the wind power generated in e.g. Belgium 

alone. 

A way of representing the beneficial effect of aggregation 

at power system scale is by plotting the load 

duration curve of wind power plants. This is a graph 

which shows how many hours the power plant is operating 

above a certain power output. Examples for a 

single wind turbine, a small country (Belgium) and the 

whole of the EU are given in Figure 13.4. Aggregating 

wind power flattens the load duration curve. A single 

offshore turbine in this example produces rated 

(100%) power for 1,500 hours and zero power during 

FiGuRe 13.1: FRequency OF Relative pOweR chanGes in inteRvals OF One hOuR FOR a sinGle danish OFFshORe wind 

FaRm, 25 danish OFFshORe wind FaRms expected in 2030 and all wind FaRms (On&OFFshORe) that aRe expected in 

denmaRk in 2030. a pOsitive value ReFlects an incRease in pOweR and a neGative value a decRease 

Occurence 

(hours per year) 

6,000 

5,000 

4,000 

3,000 

2,000 

1,000 

0 

-20 -15 -10 -5 0 5 10 15 20 

Total Danish wind power 25 Danish offshore wind parks 1 Danish offshore park 


FiGuRe 13.2: FRequency OF Relative pOweR chanGes in 1 hOuR inteRvals FROm all expected euROpean OFFshORe 

wind FaRms in 2030 (127Gw), FROm all expected euROpean OnshORe wind FaRms in 2030 (267Gw) and the sum OF all 

expected On&OFFshORe capacities in euROpe in 2030 

Occurence 

(hours per year) 

5,000 

4,000 

3,000 

2,000 

1,000 

0 

1,000 hours, whereas at the EU level, the maximum 

wind power produced is 70% of the total installed 

capacity and the minimum wind power production is 

never below 10%. This demonstrates how aggregation 

at the European level results in increasingly steady 

wind power output, although there are still periods 

with low or high wind power production. 


-8 -6 -4 -2 0 2 4 6 8 

EU onshore power EU sum of on&offshore EU offshore power 

It is important to highlight that this large-scale wind 

smoothing effect is only possible if power exchange 

can be realised across large areas and if the power 

exchange is not restricted. The grids play a crucial role 

of interconnecting wind power plant outputs installed 

at a variety of geographical locations, with different 

weather patterns. 

FiGuRe 13.3: example OF smOOthinG eFFect by GeOGRaphic dispeRsiOn. the FiGuRe cOmpaRes the hOuRly Output OF wind 

pOweR capacity in thRee aReas, includinG all expected OnshORe and OFFshORe wind FaRms in the yeaR 2030 

Power 

(% of inst. capacity) 

100 

80 

60 

40 

20 

0 

700 800 900 1,000 1,100 1,200 1,300 

BeNeLux+DE+FR Belgium EU27+NO+CH 

129


FiGuRe 13.4: duRatiOn cuRves FOR the ‘wind yeaR 2030’, FOR a sinGle OFFshORe tuRbine in FROnt OF the belGium 

cOast, FOR the sum OF all expected On&OFFshORe wind FaRms in belGium in 2030 and FOR the sum OF all expected 

On&OFFshORe wind FaRms in euROpe in 2030 

Power 

(% of inst. capacity) 

10000 

9000 

8000 

7000 

6000 

5000 

4000 

3000 

2000 

1000 

0 

0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 

The larger the grid and the larger its transmission capacity, 

the larger the smoothing effect will be of wind 

energy. This effect of course also holds for aggregation 

of demand or other weather or resource dependent 

generation sources. 

D.I.II Visualising spatial power 

correlations: von-Bremen-Maps 63 

A new way of identifying spatial correlations of 

wind power production is shown in Figure 13.5 and 

Figure 13.6. The simple idea is to calculate the correlation 

between a time series of a certain local variable, 

like local wind speed at a specific point in space, to a 

prescribed reference time series which is fixed. Then, 

all these correlations for a high number of geographical 

points, preferably for a high density of grid points, 

are plotted as a map. In this way, the map shows the 

spatial characteristics of a specific correlation. 

The von-Bremen-map in Figure 68 shows the spatial 

correlation of local wind power time series and the 

German Wind Power Generation in spring 2007. 

Figure 13.5 shows that the area which shows the highest 

correlation with the aggregated sum of the German 

Time (hours) 

Single Offshore Turbine Total Belgium On&Offshore Wind Total EU On&Offshore Wind 

63 Developed by Dr. Lueder von Bremen (ForWind) in September 2010. 

FiGuRe 13.5: vOn-bRemen-map shOwinG spatial 

cORRelatiOn between lOcal wind pOweR time seRies 

and the measuRed GeRman wind pOweR GeneRatiOn time 

seRies in spRinG 2007 

wind power generation is the region between Bremen, 

Hamburg and Hannover. This plausible result is due to 

the simple fact that the major shares of German wind 

power capacity are installed in the northern part of the 

country and the high density of turbines obviously results 

in a high correlation. The more interesting result 

is that the correlation shows a clear west-east pattern: 

The map reflects that the wind power production 

is strongly correlated from West to East (e.g. England, 

BeNeLux, Germany, Denmark and Poland), but less 


FiGuRe 13.6: vOn-bRemen-map shOwinG spatial cORRelatiOn between lOcal wind pOweR time seRies and the simulated 

tOtal eu OFFshORe wind pOweR (leFt) OR OnshORe wind pOweR (RiGht), Full yeaR 2007 

between North and South (e.g. Denmark vs. France). 

Besides the fact that the main wind direction is from 

West to East, especially the low pressure weather 

systems with strong wind speeds also move mainly 

from West to East. This leads to a correlation between 

England and Germany of about 0.50, in contrast to 

only 0.18 between France and Germany. 

Figure 13.6 shows the correlation of the local wind 

power time series with either the simulated offshore 

wind power (figure to the left) or onshore wind power 

(figure to the right) in Northern Europe, as assumed 

in the 2030 scenario of offshore grid. It reflects that 

most of the offshore capacities in the 2030 scenario 


are concentrated in the Southern North Sea. In contrast 

to this, the onshore wind power in the scenario is 

more or less evenly distributed over Northern Europe. 

In total, wind energy is clearly concentrated in the 

North. This concentration will pose considerable 

challenges regarding the power flows in the future 

European electricity grid. 

To conclude, the analysis shows that grid interconnections 

between regions of low weather correlation can 

significantly reduce the variability of European wind 

power production. The North-South direction is the 

most interesting from correlation point of view. 

table 13.1: cORRelatiOn cOeFFicients between cOuntRies usinG simulated wind pOweR time seRies FOR the 

OFFshOReGRid 2030 wind pOweR scenaRiO (On- & OFFshORe wind tOGetheR) 

Be dK et Fi Fr de UK ir lA lt nl no Pl rU Se 

Be 100% 45% 12% 2% 59% 67% 66% 37% 20% 21% 79% 12% 28% 20% 22% 

dK 45% 100% 32% 17% 32% 76% 49% 20% 44% 48% 77% 44% 78% 48% 73% 

et 12% 32% 100% 51% 10% 18% 16% 12% 66% 66% 22% 13% 36% 45% 69% 

Fi 2% 17% 51% 100% 2% 6% 7% 4% 30% 34% 10% 23% 16% 19% 49% 

Fr 59% 32% 10% 2% 100% 37% 49% 43% 16% 18% 46% 5% 23% 17% 20% 

de 67% 76% 18% 6% 37% 100% 67% 26% 28% 30% 87% 40% 53% 32% 43% 

UK 66% 49% 16% 7% 49% 67% 100% 62% 20% 21% 74% 37% 29% 21% 27% 

ir 37% 20% 12% 4% 43% 26% 62% 100% 13% 14% 33% 14% 15% 13% 13% 

lA 20% 44% 66% 30% 16% 28% 20% 13% 100% 89% 32% 15% 55% 74% 69% 

lt 21% 48% 66% 34% 18% 30% 21% 14% 89% 100% 34% 17% 61% 88% 72% 

nl 79% 77% 22% 10% 46% 87% 74% 33% 32% 34% 100% 36% 50% 34% 49% 

no 12% 44% 13% 23% 5% 40% 37% 14% 15% 17% 36% 100% 24% 16% 30% 

Pl 28% 78% 36% 16% 23% 53% 29% 15% 55% 61% 50% 24% 100% 65% 73% 

rU 20% 48% 45% 19% 17% 32% 21% 13% 74% 88% 34% 16% 65% 100% 59% 

Se 22% 73% 69% 49% 20% 43% 27% 13% 69% 72% 49% 30% 73% 59% 100% 

131 

–1 

–0.9 

–0.8 

–0.7 

–0.6 

–0.5 

–0.4 

–0.3 

–0.2 

–0.1 

–0


FiGuRe 13.7: minimum beneFicial distance FROm the wind FaRm tO shORe FOR diFFeRent inteRcOnnectOR capacities [km]. 

(aveRaGe absOlute pRice diFFeRence OF €7.5, distance wF tO inteRcOnnectOR OF 40km, unbalanced FlOw with 30% OF 

pRice diFFeRence FlOwinG tOwaRds One cOuntRy) 

Minimum distance 

WF to shore (km) 

1,500 

1,200 

900 

600 

300 

0 

100 

200 

Area A Area B 

Area C 

300 

Spatial correlations of wind power 

production between countries 

With the simulated wind power time series, also the 

spatial correlations between individual countries 

have been investigated. The results are shown in 

Table 13.1, which confirms the findings explained 

above. These figures can be used in the preliminary 

assessment of new interconnectors that are meant for 

trading wind power. 

D.II Case-independent model – 

sensitivity analysis 

400 

The case-independent model was built in order to 

carry out pre-analysis of beneficial cases of hub-tohub 

connections and tee-in connections. Furthermore 

the results of case-independent model can serve as 

quick guidelines for the modular offshore grid development 

and can give insight to policy decision makers, 

stakeholders, TSOs and interconnector and wind farm 

developers. 

The case-independent model analyses the benefits of 

a project compared to the conventional solution. The 

model takes into account a variety of parameters that 

influence the results. If the parameters of the project 

500 

600 

700 

800 

900 

1000 

Wind farm capacity (MW) 

1,500 MW interconnector 1,000 MW interconnector 500 MW interconnector 

are known, the reader can position his project within 

the field of parameters and read the economic viability 

of the project from the results given. 

The model is explained below but the detailed results 

are available on www.offshoregrid.eu due to the large 

amount of data. 

D.II.I Sensitivity analysis on the 

benefit of tee-in solutions 

Impact of interconnector capacity 

The impact of the interconnector capacity on the 

break-even distance is different for different wind farm 

capacities. These can be divided in three areas, as 

can be seen in Figure 13.7: 

• Area A: Wind farm capacities up to the interconnector 

capacity of 500 MW. 

For wind farms with a small capacity, the break-even 

distances are equal for every interconnector capacity. 

The part of the interconnection capacity which is 

higher than the wind farm capacity is unconstrained 

in both the conventional solution as the tee-in solution. 

It does therefore not lead to a difference in the 

minimum beneficial distance. 


1100 

1200 

1300 

1400 

1500 

1600 

1700 

1800 

1900 

2000

FiGuRe 13.8: minimum distance FROm the wind FaRm tO shORe FOR diFFeRent distances FROm the wind FaRm tO the 

inteRcOnnectOR [km]. (inteRcOnnectOR capacity OF 1000 mw, aveRaGe absOlute pRice diFFeRence OF €7.5, unbalanced 

FlOw with 30% OF pRice diFFeRence FlOwinG tOwaRds One cOuntRy) 

Minimum distance WF 

to shore (km) 

400 

350 

300 

250 

200 

150 

100 

50 

0 

• Area B: Wind farm capacities between 500 MW and 

1000 mw. 

As described above, the minimum distance drops 

for wind farms larger than the interconnector capacity, 

until the wind farm capacity is double the size of 

the interconnector. This is shown in Area B for the 

interconnector capacity of 500 MW. For the larger 

interconnector capacities, the curves still coincide 

as in Area A. 

• Area C: Wind farm capacities larger than 1,000 MW. 

As in area B, the break-even distance drops for 

wind farms larger than the interconnector capacity 

until double the size. In this area this is shown for 

the 1,000 MW interconnector curve. For 2,000 MW 

interconnectors, the break-even distance is larger 

than for the 1,000 MW interconnector and is still 

rising as the wind farm capacity goes to 100% the 

interconnector capacity. In Area C, the wind farm 

is larger than 200% the interconnector capacity for 

the 500 MW case. The break-even distance therefore 

rises steeply with WF capacity as the wind farm 

output would have to be curtailed due to too small 

cable capacity. 


100 300 500 700 900 1,100 1,300 1,500 1,700 1,900 


100 km 80 km 60 km 40 km 20 km 

Impact of distance of wind farm to 

interconnector 

The further a wind farm from an interconnector, the 

less beneficial it is to tee-in on that interconnector, 

and the higher the break-even distance (Figure 13.8). 

Impact of absolute price difference 

The higher the absolute difference of price levels in the 

connected countries, the more important the electricity 

trade becomes. Wind farms should then be smaller 

in order to not constrain “valuable trading capacity” of 

the cable. As a result the minimum distance increases 

with price level difference (Figure 13.9). 

Electricity price profiles and wind-price 

correlations 

• Unbalanced price profiles increase the impact of 

teed-in wind energy. 

If the price difference is not balanced, which here 

means that the price is most of the time (>50% of 

the time) lower in one country, the impact of wind 

power production becomes larger. This is because 

in case wind is blowing it blocks the possibility for 

trade. In this case one of the legs (the one connecting 

the country with lower prices) is not loaded and 

133


infrastructure remains unused. A solution would be 

to dimension this leg smaller. 

• Due to this large impact of wind teed-in to the interconnection, 

the minimum distance grows with the 

imbalance of the price levels. 

• Correlation between wind and price imbalance is 

beneficial for a tee-in solution. 

• If the price difference profile is correlated with the 

wind power production, this will have an impact on 

the minimum tee-in distance. If the price difference 

is lower when there is a lot of wind, the impact of 

constraining the cable will be less important and 

the minimum distance to shore will become shorter. 

If the price difference is higher at times of high 

wind energy production the effect is opposite. 

FiGuRe 13.9: minimum distance FROm the wind FaRm tO shORe FOR diFFeRent aveRaGe absOlute pRice diFFeRences [km]. 

(inteRcOnnectOR capacity OF 1000 mw, aveRaGe absOlute pRice diFFeRence OF €7.5, unbalanced FlOw with 30% OF 

pRice diFFeRence FlOwinG tOwaRds One cOuntRy impact OF distance wF tO inteRcOnnectOR) 

Minimum distance WF 

from shore (km) 

900 

800 

700 

600 

500 

400 

300 

200 

100 

0 

100 300 500 700 900 1,100 1,300 1,500 1,700 1,900 


20 EUR 15 EUR 10 EUR 7.5 EUR 5 EUR 2.5 EUR 

FiGuRe 13.10: impact OF incReasinG inteRcOnnectOR capacity On the maximum beneFicial distance FOR hub-hub 

inteRcOnnectORs. (diRect inteRcOnnectOR distance tO which cOmpaRed: 500 mw, aveRaGe absOlute pRice diFFeRence 

between the cOuntRies: €5/mwh) 



600 

500 

400 

300 

200 

100 

0 

100 

200 

300 

400 

500 

600 

700 

800 

500 MW hub-to-hub interconnector 

900 



1,000 

1,100 

1,200 

1,300 

1,400 

1,500 

1,600 

1,700 

1,800 

1,000 MW hub-to-hub interconnector 

1,900 

2,000

D.II.II Sensitivity analysis on the 

benefit of hub-to-hub solutions 

Impact of interconnector capacity 

For wind farm capacities which are smaller than the interconnector 

capacity, the wind farm connections are 

the constraining factor for the trade. Increasing the 


interconnector capacity further only leads to additional 

infrastructure costs and thus lowers the maximum 

beneficial distance between hubs (Figure 13.10). 

Impact of distance between countries 

(direct interconnection length) 

The larger the distance between two countries (and 

thus the larger the direct interconnector length to 

FiGuRe 13.11: maximum distance between hubs FOR diFFeRent diRect inteRcOnnectOR lenGths [km] (inteRcOnnectOR 

capacity OF 500 mw, aveRaGe absOlute pRice diFFeRence OF €5, unbalanced FlOw with 30% OF pRice diFFeRence 

FlOwinG tOwaRds One cOuntRy) 



1,000 

900 

800 

700 

600 

500 

400 

300 

200 

100 

0 

100 

200 

300 

400 

500 

600 

100 km 200 km 

700 

800 

900 

1,000 

1,100 

1,200 


400 km 

1,300 

600 km 

1,400 

- 

1,500 

1,600 

800 km 

1,700 

1,800 

1,900 

2,000 

1,000 km 

FiGuRe 13.12: maximum distance between hubs FOR diFFeRent wF capacities and seveRal aveRaGe absOlute pRice 

diFFeRences [€/mwh] (inteRcOnnectOR capacity OF 500 mw, diRect inteRcOnnectOR OF 500 km, unbalanced FlOw with 

30% OF pRice diFFeRence FlOwinG tOwaRds One cOuntRy) 



600 

500 

400 

300 

200 

100 

0 

100 

200 

300 

400 

5 7,5 

500 

600 

10 

700 

800 

900 

1,000 

1,100 

1,200 

1,300 

1,400 


15 

20 

1,500 

1,600 

1,700 

1,800 

1,900 

2,000 

135


FiGuRe 13.13: maximum distance between hubs FOR asymmetRic wind FaRm hubs capacity - diFFeRent pROFiles OF pRice 

diFFeRence (30% tO cOuntRy a, 50% tO eitheR cOuntRy, and 70% tO cOuntRy b) [€/mwh] (inteRcOnnectOR capacity OF 

500 mw, wind FaRm capacity in cOuntRy 2 is twice the size OF the wind FaRm in cOuntRy a) 



400 

300 

200 

100 

0 

100 200 300 400 500 600 700 800 900 1,000 

30% 

50% 

which is compared), the more infrastructure costs will 

be saved by interconnecting hubs. The maximum beneficial 

distance between hubs therefore increases with 

increasing direct interconnector length (Figure 13.11). 

Impact of absolute price difference 

The higher the absolute price difference between the 

countries, the more the trade of electricity becomes 

important and the less the interconnector cable 

should be constrained. For higher absolute price differences, 

the reduction in infrastructure costs due 

to the reduced cable length must be higher to cover 

the reduction in system benefits. The maximum distance 

between hubs in these cases is therefore lower 

(Figure 13.12). 

Electricity price profiles and wind-price 

correlations 

• Unbalanced price profiles have no impact 

If the price difference is not balanced, which here 

means that the price is most of the time (>50% of 

the time) lower in one country, one of the legs (the 

one connecting the country with lower prices) is not 

often loaded and infrastructure remains unused 

(the leg connecting the country with lower prices). 

However, as the constraints on the cables are independent 

on the direction of the price difference 


70% 

when the cable capacities are identical, this has 

no effect on the break—even distance. The constraints 

can be partly relieved by dimensioning one 

leg bigger and the other leg smaller. 

• Correlation between wind and price imbalance increases 

the impact. 

• As before with the tee-in solutions (paragraph 

4.4.1), a correlation between the wind power production 

and the price imbalance has a negative 

effect on the economics of integrated solutions 

compared to the business as usual case. Similarly, 

an inverse correlation has a positive effect. 

Impact of asymmetric wind farm hub 

capacities 

In Figure 13.13 the effect of asymmetric wind farm 

hub capacities is analysed. The wind farm hub in country 

A is 50% smaller than the wind farm hub in country 

B. The wind farm connection cable in country B is thus 

double the size of the connection cable in country A so 

that wind power from both hubs can flow to the country 

with the highest prices most of the time (country 

B). Figure 13.13 confirms that when prices are more 

often higher in country B (30% of price difference balanced 

to country A), the trade is less constrained 

which leads to a higher maximum distance between 

hubs. 


D.III Overall grid design 

D.III.I Direct interconnectors 

Table 13.2 shows the direct and hub-to-hub interconnectors 

that were identified as being beneficial and 

used in the first stage of the direct overall grid design. 

D.III.II Split wind farms 

Table 13.3 shows the interconnectors that were identified 

as being beneficial and used in the first stage of 

the split overall grid design. 

table 13.2: diRect & hub - hub inteRcOnnectORs identiFied 

D.III.III Tested meshed 

interconnectors 

To give an indication of the number of simulations run, 

this paragraph gives an overview of all the interconnectors 

tested for the mesh (Table 13.4). This vast 

number of possible interconnectors was considered in 

order to assess the optimal meshed design in step 3 

of the Direct and Split Design methodology. 

D.III.IV Price level differences 

between countries 

As for any other good also for electricity, trade between 

regions follows the price level differences or in other 

type country From name country to name MW Voltage technology 

Direct SE Kruseberg DE Bentwisch 1,000 500 HVDC CSC 

Direct FI Espoo EE Harku 1,000 500 HVDC CSC 

Direct SE Stärnö PL Ustka 1,000 500 HVDC CSC 

Direct SE Herslev (DK East) DK Starebaelt 1,000 500 HVDC CSC 

Direct SE Selemåla LV Grobina 1,000 500 HVDC CSC 

Direct GB Bolney FR Penly 1,000 500 HVDC CSC 

Direct SE Kruseberg DE Bentwisch 1,000 500 HVDC CSC 

Direct GB Richborough BE Zeebrugge 1,000 500 HVDC CSC 

Direct GB Bolney FR Penly 1,000 500 HVDC CSC 

Direct SE Stärnö PL Ustka 1,000 500 HVDC CSC 

Direct SE Herslev (DK East) DK Starebaelt 1,000 500 HVDC CSC 

Direct IE Knockraha FR La Martyre 1,000 500 HVDC CSC 

Direct IE Woodland GB Deeside 1,000 500 HVDC CSC 

Direct GB Richborough BE Zeebrugge 1,000 500 HVDC CSC 

Hub - Hub SE Stora Middelgrund DK Djursland/Anholt 500 320 HVDC VSC 

Hub - Hub NL IJmuiden Hub 03 GB Norfolk_B_Hub 1,000 500 HVDC VSC 

Hub - Hub GB Dogger Bank E DE Gaia Group 1,000 500 HVDC VSC 

total 16,500 

table 13.3: split desiGn inteRcOnnectORs 

type countryFrom name countryto name MW Voltage technology 

Windfarm Hub DE Ventotec Ost 2 Hub SE Kruseberg 436 320 HVDC VSC 

Onshore Substation FI Espoo EE Harku 1,000 500 HVDC VSC 

Windfarm SE Södra Midsjöbanken PL Lubiatowo 1,000 320 HVDC VSC 

Onshore Substation SE Selemåla LV Grobina 1,000 500 HVDC VSC 

Onshore Substation GB Bolney FR Penly 1,000 500 HVDC VSC 

Windfarm Hub DE Arkona-Becken Südost SE Kruseberg 450 320 HVDC VSC 

Windfarm Hub BE Belgium Zone 2 GB Richborough 900 500 HVDC VSC 

Onshore Substation GB Bolney FR Penly 1,000 500 HVDC VSC 

Windfarm Hub PL P25 Hub SE Stärnö 450 320 HVDC VSC 

Onshore Substation IE Knockraha FR La Martyre 1,000 500 HVDC VSC 

Windfarm IE 

Codling Wind Park 

extension 

GB Pentir 1,000 500 HVDC VSC 

Onshore Substation BE Zeebrugge GB Richborough 1,000 500 HVDC VSC 

Hub - Hub NL IJmuiden Hub 03 GB Norfolk B Hub 1,000 500 HVDC VSC 

Hub - Hub GB Dogger Bank E Hub DE Gaia Group Hub 1,000 500 HVDC VSC 


total 12,236 

137


table 13.4: tested mesh inteRcOnnectORs 

case country From name country to name MW Voltage technology Mesh design 

h_1 NL IJmuiden Hub 03 DE Gaia Group 1,000 500 HVDC VSC - 

h_2 NO Idunn DE Gaia Group 1,000 500 HVDC VSC - 

h_3 NO Idunn SE Skogssater 1,000 500 HVDC VSC - 

h_4 NL IJmuiden Hub 03 BE Zeebrugge 1,000 500 HVDC VSC Direct + Split 

h_5 NO Idunn DE Gaia Group 2,000 500 HVDC VSC - 

h_6 NO Lista NO Idunn 2,000 500 HVDC VSC Split 

h_7 NL IJmuiden Hub 03 DE Gaia Group 2,000 500 HVDC VSC - 

h_8 NL Oterleek BE Zeebrugge 1,000 500 HVDC VSC - 

h_9 NO Lista SE Skogssater 1,000 500 HVDC VSC Direct 

h_10 NO Idunn GB Dogger Bank E 1,000 500 HVDC VSC Direct 

h_11 GB Dogger Bank E NL IJmuiden Hub 3 1,000 500 HVDC VSC Split 

h_12 NO Idunn GB Dogger Bank E 2,000 500 HVDC VSC Split 

h_13 GB Dogger Bank E NL IJmuiden Hub 3 2,000 500 HVDC VSC - 

h_14 GB Dogger Bank E DE Gaia Group 2,000 500 HVDC VSC - 

h_15 DE Gaia Group DE 

Globaltech 

Group 

1,000 500 HVDC VSC - 

h_16 NL IJmuiden Hub 03 NL IJmuiden Hub 2 1,000 500 HVDC VSC - 

h_17 GB Dogger Bank E GB Dogger Bank C 1,000 500 HVDC VSC Split 

h_18 SE 

Södra 

Midsjöbanken 

LT Klaipeda 1,000 320 HVDC VSC - 

h_19 DE 

Arkona-Becken 

Südost 

words electricity is bought where it is cheapest and 

it is sold where it can be sold for the highest price. 

If interconnection capacity would be unlimited, the 

wholesale market price levels would be equal across 

Europe. However the limited interconnection capacity 

between countries limits the trade and the prices cannot 

be fully levelled. The price differences thus reflect 

the price for transmission capacity between countries. 

If new interconnecting lines are built either on- or offshore, 

the trading volumes are increased and price 

levels differences are reduced. One could also interpret 

it as follows: the supply curve of interconnection 

capacity is increased and therefore the price for it is 

reduced. 

In particular new transmission capacities allow the 

electricity to be produced where the production costs 

are lowest and therefore additional transmission 

capacity can lower the overall electricity generation 

costs. This system cost reduction is considered as 

the benefits of the transmission capacity that has to 

be compared with the infrastructure cost in order to 

determine the net benefits. 

SE 

Södra 

Midsjöbanken 

1,000 320 HVDC VSC - 

In order to assess this task the price levels between 

all countries were listed and the highest price levels 

were identified. This sorted list of highest price differences 

between countries was used as an indicator for 

the most beneficial interconnections. As detailed in 

chapter 4.5 the OffshoreGrid consortium tested two 

methodologies. The Direct Design approach and the 

Split Design approach: 

• The Direct Design approach starts from the Hub 

Base Case scenario 2030 and adds direct interconnections 

between the countries. In the next step 

hub-to-hub connections and finally meshed grid elements 

are added. 

• The Split Design equals the Direct Design, but 

in the first step the direct interconnections are 

mirrored with split wind farm connections (s. chapter 

4.3.1) where beneficial. 

At each of these steps the price levels between the 

countries are changed. This is displayed for the direct 

approach in Table 13.6 and for the Split Design approach 

in Table 13.5. 


table 13.5: diRect desiGn appROach - pRice level diFFeRences between the cOuntRies aFteR diFFeRent desiGn 

RealisatiOns 


Be Base Case 4,6 9,7 6,4 23,7 10,1 9,4 8,2 6,9 6,4 7,0 17,5 6,0 25,9 

Direct 4,0 6,7 8,4 11,9 7,6 6,2 7,1 7,2 8,1 5,0 15,5 6,1 11,0 

Hub-to-hub 4,1 6,8 8,3 11,7 6,4 5,4 6,5 7,2 8,0 4,3 16,3 6,3 10,9 

Meshed 4,1 6,3 8,0 11,4 5,8 4,6 6,0 7,0 7,7 3,3 15,6 6,2 10,5 

de Base Case 4,6 7,5 5,4 22,1 9,5 8,8 8,8 5,4 5,4 5,3 15,7 4,4 24,0 

Direct 4,0 5,8 7,8 11,4 8,5 7,6 8,7 6,1 7,3 4,8 15,2 4,7 10,3 

Hub-to-hub 4,1 6,3 7,7 11,5 8,3 7,4 8,4 6,3 7,2 4,9 16,4 5,0 10,6 

Meshed 4,1 6,1 7,7 11,5 8,3 7,3 8,3 6,3 7,2 4,5 16,0 5,0 10,5 

dK Base Case 9,7 7,5 6,2 16,2 7,6 8,9 11,4 5,8 6,2 6,3 10,1 6,9 17,0 

Direct 6,7 5,8 4,7 7,2 6,7 7,1 8,8 3,0 4,1 4,4 10,7 3,7 5,6 

Hub-to-hub 6,8 6,3 4,6 7,0 6,5 6,7 8,6 3,0 4,0 4,3 11,3 3,4 5,5 

Meshed 6,3 6,1 4,6 7,1 6,4 6,3 8,3 3,0 4,0 4,2 11,1 3,3 5,6 

ee Base Case 6,4 5,4 6,2 18,8 8,5 10,0 10,4 1,2 0,0 8,1 13,4 3,7 21,1 

Direct 8,4 7,8 4,7 4,0 7,8 9,0 10,7 2,7 1,0 7,9 9,0 5,6 4,0 

Hub-to-hub 8,3 7,7 4,6 4,1 7,6 8,5 10,3 2,4 0,9 7,4 9,9 5,0 4,1 

Meshed 8,0 7,7 4,6 4,1 7,6 8,2 10,1 2,4 0,9 7,3 9,6 5,0 4,1 

Fi Base Case 23,7 22,1 16,2 18,8 16,5 20,3 23,4 19,0 18,8 20,7 9,9 20,9 7,3 

Direct 11,9 11,4 7,2 4,0 9,0 11,0 12,9 6,3 4,7 10,6 5,7 9,1 2,1 

Hub-to-hub 11,7 11,5 7,0 4,1 9,0 10,5 12,5 6,1 4,7 10,2 6,3 8,5 2,0 

Meshed 11,4 11,5 7,1 4,1 9,0 10,3 12,4 6,1 4,7 10,2 6,1 8,4 2,0 

Fr Base Case 10,1 9,5 7,6 8,5 16,5 8,9 11,3 8,5 8,5 8,3 10,6 9,6 17,2 

Direct 7,6 8,5 6,7 7,8 9,0 5,8 6,9 7,2 7,6 6,5 10,5 8,0 8,2 

Hub-to-hub 6,4 8,3 6,5 7,6 9,0 5,2 6,5 7,1 7,4 5,9 11,7 7,6 8,3 

Meshed 5,8 8,3 6,4 7,6 9,0 4,9 6,3 7,1 7,4 5,6 11,4 7,5 8,2 

GB Base Case 9,4 8,8 8,9 10,0 20,3 8,9 6,1 9,9 10,0 6,5 15,0 10,0 21,2 

Direct 6,2 7,6 7,1 9,0 11,0 5,8 4,1 8,1 8,7 5,3 13,0 8,2 10,0 

Hub-to-hub 5,4 7,4 6,7 8,5 10,5 5,2 4,1 7,7 8,2 4,6 13,6 7,7 9,6 

Meshed 4,6 7,3 6,3 8,2 10,3 4,9 4,1 7,4 7,9 4,1 13,1 7,4 9,3 

ie Base Case 8,2 8,8 11,4 10,4 23,4 11,3 6,1 10,6 10,4 8,6 18,1 10,2 24,8 

Direct 7,1 8,7 8,8 10,7 12,9 6,9 4,1 9,8 10,4 7,0 15,1 9,5 12,0 

Hub-to-hub 6,5 8,4 8,6 10,3 12,5 6,5 4,1 9,4 10,0 6,4 15,7 9,1 11,7 

Meshed 6,0 8,3 8,3 10,1 12,4 6,3 4,1 9,3 9,8 6,0 15,2 8,9 11,5 

lt Base Case 6,9 5,4 5,8 1,2 19,0 8,5 9,9 10,6 1,2 7,8 13,4 2,8 20,5 

Direct 7,2 6,1 3,0 2,7 6,3 7,2 8,1 9,8 1,8 6,3 10,2 3,0 5,0 

Hub-to-hub 7,2 6,3 3,0 2,4 6,1 7,1 7,7 9,4 1,5 6,0 10,9 2,6 5,0 

Meshed 7,0 6,3 3,0 2,4 6,1 7,1 7,4 9,3 1,5 5,9 10,6 2,6 4,9 

lV Base Case 6,4 5,4 6,2 0,0 18,8 8,5 10,0 10,4 1,2 8,1 13,4 3,7 21,1 

Direct 8,1 7,3 4,1 1,0 4,7 7,6 8,7 10,4 1,8 7,4 9,2 4,7 4,0 

Hub-to-hub 8,0 7,2 4,0 0,9 4,7 7,4 8,2 10,0 1,5 6,9 10,1 4,1 4,1 

Meshed 7,7 7,2 4,0 0,9 4,7 7,4 7,9 9,8 1,5 6,8 9,8 4,1 4,0 

nl Base Case 7,0 5,3 6,3 8,1 20,7 8,3 6,5 8,6 7,8 8,1 14,7 7,2 21,2 

Direct 5,0 4,8 4,4 7,9 10,6 6,5 5,3 7,0 6,3 7,4 13,3 5,8 9,2 

Hub-to-hub 4,3 4,9 4,3 7,4 10,2 5,9 4,6 6,4 6,0 6,9 13,9 5,6 9,0 

Meshed 3,3 4,5 4,2 7,3 10,2 5,6 4,1 6,0 5,9 6,8 13,8 5,4 8,9 

no Base Case 17,5 15,7 10,1 13,4 9,9 10,6 15,0 18,1 13,4 13,4 14,7 14,8 8,8 

Direct 15,5 15,2 10,7 9,0 5,7 10,5 13,0 15,1 10,2 9,2 13,3 12,6 5,6 

Hub-to-hub 16,3 16,4 11,3 9,9 6,3 11,7 13,6 15,7 10,9 10,1 13,9 13,0 6,3 

Meshed 15,6 16,0 11,1 9,6 6,1 11,4 13,1 15,2 10,6 9,8 13,8 12,7 6,1 

Pl Base Case 6,0 4,4 6,9 3,7 20,9 9,6 10,0 10,2 2,8 3,7 7,2 14,8 22,1 

Direct 6,1 4,7 3,7 5,6 9,1 8,0 8,2 9,5 3,0 4,7 5,8 12,6 7,6 

Hub-to-hub 6,3 5,0 3,4 5,0 8,5 7,6 7,7 9,1 2,6 4,1 5,6 13,0 7,2 

Meshed 6,2 5,0 3,3 5,0 8,4 7,5 7,4 8,9 2,6 4,1 5,4 12,7 7,1 

Se Base Case 25,9 24,0 17,0 21,1 7,3 17,2 21,2 24,8 20,5 21,1 21,2 8,8 22,1 

Direct 11,0 10,3 5,6 4,0 2,1 8,2 10,0 12,0 5,0 4,0 9,2 5,6 7,6 

Hub-to-hub 10,9 10,6 5,5 4,1 2,0 8,3 9,6 11,7 5,0 4,1 9,0 6,3 7,2 

Meshed 10,5 10,5 5,6 4,1 2,0 8,2 9,3 11,5 4,9 4,0 8,9 6,1 7,1 


139


table 13.6: split-desiGn appROach - pRice level diFFeRences between the cOuntRies aFteR diFFeRent desiGn 

RealisatiOns 


Be Base Case 4,6 9,7 6,4 23,7 10,1 9,4 8,2 6,9 6,4 7,0 17,5 6,0 25,9 

Direct 4,2 7,7 9,7 14,0 8,0 6,8 7,5 8,4 9,2 5,8 17,1 6,6 13,6 

Hub-to-hub 4,1 7,2 9,6 14,0 7,9 6,7 7,4 8,3 9,1 5,6 15,7 6,4 13,4 

Meshed 3,9 5,5 8,8 12,9 5,4 4,4 5,9 7,4 8,2 2,8 14,3 6,0 12,1 

de Base Case 4,6 7,5 5,4 22,1 9,5 8,8 8,8 5,4 5,4 5,3 15,7 4,4 24,0 

Direct 4,2 6,5 8,9 13,3 8,8 8,0 8,8 7,2 8,2 5,3 16,5 5,1 12,8 

Hub-to-hub 4,1 6,2 9,1 13,5 8,8 7,8 8,6 7,3 8,3 5,4 15,3 5,2 12,7 

Meshed 3,9 6,0 9,1 13,7 8,2 7,1 8,2 7,4 8,4 4,4 15,4 5,2 12,9 

dK Base Case 9,7 7,5 6,2 16,2 7,6 8,9 11,4 5,8 6,2 6,3 10,1 6,9 17,0 

Direct 7,7 6,5 5,7 8,8 6,8 7,3 9,1 4,1 4,9 4,6 11,4 4,4 7,8 

Hub-to-hub 7,2 6,2 5,8 9,1 6,6 6,7 8,6 4,1 4,9 4,5 10,6 4,1 7,9 

Meshed 5,5 6,0 5,7 9,1 5,9 5,6 7,8 4,0 4,8 3,9 10,4 4,0 7,8 

ee Base Case 6,4 5,4 6,2 18,8 8,5 10,0 10,4 1,2 0,0 8,1 13,4 3,7 21,1 

Direct 9,7 8,9 5,7 4,8 8,2 9,7 11,2 2,7 1,2 8,9 9,4 6,3 5,1 

Hub-to-hub 9,6 9,1 5,8 4,9 8,2 9,4 11,1 2,7 1,2 9,0 8,5 6,4 5,1 

Meshed 8,8 9,1 5,7 4,9 7,9 8,7 10,6 2,7 1,2 8,2 8,4 6,3 5,0 

Fi Base Case 23,7 22,1 16,2 18,8 16,5 20,3 23,4 19,0 18,8 20,7 9,9 20,9 7,3 

Direct 14,0 13,3 8,8 4,8 10,1 12,3 14,0 7,0 5,7 12,1 5,7 10,5 2,2 

Hub-to-hub 14,0 13,5 9,1 4,9 10,1 12,1 14,0 7,2 5,8 12,3 5,3 10,7 2,4 

Meshed 12,9 13,7 9,1 4,9 10,2 11,4 13,6 7,2 5,8 11,9 5,3 10,7 2,4 

Fr Base Case 10,1 9,5 7,6 8,5 16,5 8,9 11,3 8,5 8,5 8,3 10,6 9,6 17,2 

Direct 8,0 8,8 6,8 8,2 10,1 5,9 7,0 7,6 7,9 6,7 11,6 8,2 9,6 

Hub-to-hub 7,9 8,8 6,6 8,2 10,1 5,7 6,9 7,5 7,9 6,5 10,5 8,1 9,4 

Meshed 5,4 8,2 5,9 7,9 10,2 4,7 6,2 7,2 7,6 5,3 10,4 7,6 9,3 

GB Base Case 9,4 8,8 8,9 10,0 20,3 8,9 6,1 9,9 10,0 6,5 15,0 10,0 21,2 

Direct 6,8 8,0 7,3 9,7 12,3 5,9 4,5 8,8 9,3 5,4 14,1 8,5 11,7 

Hub-to-hub 6,7 7,8 6,7 9,4 12,1 5,7 4,5 8,4 8,9 4,7 12,8 8,2 11,2 

Meshed 4,4 7,1 5,6 8,7 11,4 4,7 4,4 7,6 8,1 3,7 11,9 7,3 10,4 

ie Base Case 8,2 8,8 11,4 10,4 23,4 11,3 6,1 10,6 10,4 8,6 18,1 10,2 24,8 

Direct 7,5 8,8 9,1 11,2 14,0 7,0 4,5 10,2 10,8 7,3 16,0 9,6 13,5 

Hub-to-hub 7,4 8,6 8,6 11,1 14,0 6,9 4,5 10,0 10,6 6,8 14,8 9,4 13,2 

Meshed 5,9 8,2 7,8 10,6 13,6 6,2 4,4 9,5 10,1 5,8 14,2 8,8 12,7 

lt Base Case 6,9 5,4 5,8 1,2 19,0 8,5 9,9 10,6 1,2 7,8 13,4 2,8 20,5 

Direct 8,4 7,2 4,1 2,7 7,0 7,6 8,8 10,2 1,5 7,4 10,4 3,7 6,3 

Hub-to-hub 8,3 7,3 4,1 2,7 7,2 7,5 8,4 10,0 1,5 7,4 9,3 3,7 6,2 

Meshed 7,4 7,4 4,0 2,7 7,2 7,2 7,6 9,5 1,5 6,7 9,1 3,7 6,1 

lV Base Case 6,4 5,4 6,2 0,0 18,8 8,5 10,0 10,4 1,2 8,1 13,4 3,7 21,1 

Direct 9,2 8,2 4,9 1,2 5,7 7,9 9,3 10,8 1,5 8,2 9,6 5,2 5,3 

Hub-to-hub 9,1 8,3 4,9 1,2 5,8 7,9 8,9 10,6 1,5 8,3 8,7 5,2 5,2 

Meshed 8,2 8,4 4,8 1,2 5,8 7,6 8,1 10,1 1,5 7,5 8,5 5,2 5,1 

nl Base Case 7,0 5,3 6,3 8,1 20,7 8,3 6,5 8,6 7,8 8,1 14,7 7,2 21,2 

Direct 5,8 5,3 4,6 8,9 12,1 6,7 5,4 7,3 7,4 8,2 14,2 6,4 11,2 

Hub-to-hub 5,6 5,4 4,5 9,0 12,3 6,5 4,7 6,8 7,4 8,3 13,2 6,4 11,1 

Meshed 2,8 4,4 3,9 8,2 11,9 5,3 3,7 5,8 6,7 7,5 12,9 5,6 10,8 

no Base Case 17,5 15,7 10,1 13,4 9,9 10,6 15,0 18,1 13,4 13,4 14,7 14,8 8,8 

Direct 17,1 16,5 11,4 9,4 5,7 11,6 14,1 16,0 10,4 9,6 14,2 13,5 4,9 

Hub-to-hub 15,7 15,3 10,6 8,5 5,3 10,5 12,8 14,8 9,3 8,7 13,2 12,4 4,3 

Meshed 14,3 15,4 10,4 8,4 5,3 10,4 11,9 14,2 9,1 8,5 12,9 12,2 4,2 

Pl Base Case 6,0 4,4 6,9 3,7 20,9 9,6 10,0 10,2 2,8 3,7 7,2 14,8 22,1 

Direct 6,6 5,1 4,4 6,3 10,5 8,2 8,5 9,6 3,7 5,2 6,4 13,5 9,7 

Hub-to-hub 6,4 5,2 4,1 6,4 10,7 8,1 8,2 9,4 3,7 5,2 6,4 12,4 9,6 

Meshed 6,0 5,2 4,0 6,3 10,7 7,6 7,3 8,8 3,7 5,2 5,6 12,2 9,5 

Se Base Case 25,9 24,0 17,0 21,1 7,3 17,2 21,2 24,8 20,5 21,1 21,2 8,8 22,1 

Direct 13,6 12,8 7,8 5,1 2,2 9,6 11,7 13,5 6,3 5,3 11,2 4,9 9,7 

Hub-to-hub 13,4 12,7 7,9 5,1 2,4 9,4 11,2 13,2 6,2 5,2 11,1 4,3 9,6 

Meshed 12,1 12,9 7,8 5,0 2,4 9,3 10,4 12,7 6,1 5,1 10,8 4,2 9,5 


table 13.7: cORRelatiOn cOeFFicients 

Base case direct design Split design 

Base case Final design Δ Base case Final design Δ Base case 

All wind / all hydro -0.29 -0.32 -0.03 -0.32 -0.03 

All wind / all gas -0.05 -0.04 0.01 -0.05 0.01 

All wind / all lignite coal -0.36 -0.30 0.06 -0.31 0.05 

All wind / all hard coal -0.41 -0.39 0.02 -0.40 0.01 

All wind / all “other 

renewable” 

-0.65 -0.64 0.01 -0.63 0.02 

All wind / all nuclear 0.40 0.40 0.00 0.40 0.01 

All wind / demand 0.29 0.28 -0.01 0.28 -0.01 

Due to the price level changes and the immediate impact 

on the benefits of already existing infrastructure 

a large number of iterations had to be carried out in 

order to indentify the most beneficial interconnectors. 

Please note that the absolute price levels in the countries 

might increase with further connections. Norway 

e.g. exhibits very low price levels in the Hub Base 

Case scenario 2030. If thus this low price electricity is 

sold to other countries the internal price level rises as 

higher priced generation capacity will have to be used. 

Please note that Table 13.5 and Table 13.6 only show 

price level differences and not absolute price levels. 

These price levels decrease in general, but also here 

increasing price level differences are possible. 

D.III.V Power system impact 

Balancing of wind power variability 

The offshore grid leads to the spatial smoothing of 

short term renewable energy variations and as such 

reduces the needs for balancing power in the system 

to a certain extent. This paragraph illustrates how the 

balancing of variable wind power is affected by the offshore 

grid, with a special focus on the hydro power in 

Scandinavia. 

A priori, there are two competing hypotheses: 

• the offshore grid enables cheaper generation units 

farther away from demand centres to momentarily 

replace more expensive generation units independently 

of Scandinavian hydro capability, 


• the offshore grid improves the utilisation of 

Scandinavian hydro capability. At low price periods, 

Scandinavia will import cheaper power from the 

surrounding areas, and at high price periods, will 

export power. This makes more expensive generation 

units in the surrounding areas unnecessary. 

Although it was shown in section 4.5.6 that there is 

an overall shift from hard coal and gas towards the 

cheaper category “other renewables” it is not immediately 

clear when in time this shift occurs. For example, 

it could be a shift that is evident hour by hour (first 

hypothesis), or a shift that occurs indirectly via hydro 

balancing (second hypothesis). 

Measuring the balancing of wind power can be done by 

evaluating the correlation coefficients between wind 

power production and other power production. A generation 

type that balances wind power has a negative 

correlation with wind power. This means that it produces 

when there is low wind generation and it stops 

production when wind power is generated. Table 13.7 

shows correlation coefficients between total wind production 

and total production of other generation types. 

For the assessment of grid influence on wind power 

balancing, the interesting information in Table 13.7 is 

the change in correlation coefficients relative to the 

base case. 

Both the direct and split grid designs have an increased 

anti-correlation between wind and hydro 

compared to the base case. This is interpreted as an 

increased balancing of wind by the hydro systems. For 

141

Annexes 

coal and gas, there is a decrease in anti-correlation. 

This result supports the second hypothesis presented 

above: With an expanded grid, hydro power replaces, 

to some extent, coal and gas in balancing variable 

wind power. 

It should be noted that the model was adapted to 

the specifics need to identify highly efficient offshore 

grids. Balancing power was not in the focus of the 

study and due to the trade-off between practicality 

and detail, some technicalities like start-up time and 

costs, ramp-rate and minimum up- and down-times 

have not been included in the model. The model is already 

fairly detailed and takes about two hours to run 

one simulation. Introducing further details means that 

the optimisation takes even longer and fewer simulations 

can be performed. 

In conclusion, the above discussion demonstrates 

that an expanded grid gives an increase in the balancing 

of variable wind power by hydro power and confirms 

the second hypothesis. Further development of the 

model would be needed to confirm also the first hypothesis 

and discuss the relative importance of the 

two effects. 


Annex e – reGUlAtory FrAMeWorKS 

And SUPPort ScheMeS 

Photo: Vestas

Annex e – regulatory Frameworks and Support Schemes 

table 14.1: OFFshORe ReGulatORy FRamewORks 

dK de Se UK nl Fi Pl ie no lV lU ee Be Fr explanation 

“CS = Certificate System 

FT = Feed-In Tariff 

FT+CS = Feed-In Tariff plus 

Certificate System 

B/FT = Bonus or Feed-In Tariff 

0 = None” 

CS FT 

B/FT 

(see footnote 4) 

FT 0 FT FT 

FT+ CS 

(see footnote 3) 

0 

negotiated FT 

(see foot-note 2) 

FT CS CS 

negotiated FT 

(see foot-note 1) 

Support scheme 

ü ü ü 

ü ü ü ü ü ü ü ü ü 

ü ü ü ü 

Priority grid connection 

for offshore wind 

Obligation on the TSO 

to provide connection 

to offshore wind park 

Location of offshore 

wind farms outside 

territorial waters 

Territorial waters are the 

waters included in the 12 

nm-zone 

“DM = Direct marketing 

possible 

NDM = No direct marketing 

CDM = It can be chosen 

between DM or FT” 

“T = country’s territory on land 

and at sea (including EEZ) 

Marketing options DM CDM DM DM DM DM CDM NDM DM CDM n/a CDM DM CDM 

Geographical limitation 

for support schemes 

S = electricity generated in the county’s system 

O = other” 


S S T T O* T T O** O*** T T T T T 

Sources: discussion with experts, own analysis, findings of country surveys, http:// 

res-legal.eu and CEER: Regulatory aspects of the integration of wind generation in 

European electricity markets, 2009 

1) in other publications the term negotiated feed-in tariff is also referred to as bonus, premium or negotiated prices. However it is suggested not to use the term bonus 

in this case. 

2) See footnote 1) and: existing offshore wind farms receive a fix feed-in tariff, new offshore wind farms a negotiated feed-in tariff. 

3) The main support mechanism in Poland is a quota system is combined with a certificate trading system. The price for renewable electricity (feed-in tariff) is set every 

year by the regulator and equals the average electricity price of the previous year. 

4) Plant operators have the choice to sell electricity to a supplier chosen by the transmission grid operator and receive a guaranteed price or sell electricity on the market 

and receive a bonus on top of the market price. 

* Electricity generated within Dutch systems, tax reduction also for electrcity generated in other areas. 

** Irish territory and European Union, if it does not contribute to the achievement of the member state’s energy goals. 

*** Currently no support scheme only grants, although no geographic limits, projects must be relevant for the Norwegian energy market. 

n/a: no information available

Annex F – trAnSFer to the 

MediterrAneAn reGion 

Photo: Vestas

Annex F – transfer to the Mediterranean region 

F.I Introduction and drivers 

The idea of creating a European super grid is not 

new and the Mediterranean region will be a fundamental 

part of this grid. OffshoreGrid focuses on the 

integration of international electricity infrastructure 

and offshore wind energy, and therefore focuses on 

Northern Europe. This section provides a qualitative 

analysis for the Mediterranean region, and investigates 

how the results of the previous chapters can be 

interpreted in a Mediterranean context. 

The Mediterranean context is much different from 

Northern Europe: 

• In Southern Europe, the same drivers for developing 

interconnections exist 64 . However, where the economical 

trade of electricity and the integration of 

renewables can be seen as the main drivers in the 

North today, most of the power interconnections between 

countries and regions in the Mediterranean 

are (being) built for reasons of security of supply. 

• Market integration is much lower in the 

Mediterranean region. Many electrical interconnections 

exist or are in development stage, but 

combining them with an integrated international 

power pool as in Northern Europe is today still unrealistic 

and very challenging. 

At the same time, numerous benefits exist that 

make an interconnected (on/offshore) grid in the 

Mediterranean very interesting. Mediterranean countries 

fall within three time zones, have different 

climatic conditions and renewable energy resources, 

different living standards and habits. An interconnected 

grid would be very helpful for the stability of 

the system, the reduction of variability, the balancing 

of surplus electricity and deficits, the optimisation of 

the operation of the national power systems, and the 

economical trade between countries. 

In the next sections, the Mediterranean countries are 

examined in three wider sub-regions: 

• North Mediterranean 

– EU countries: Cyprus, France, Greece, Italy, 

Malta, Portugal, Slovenia, and Spain. 

– Non-EU countries: Albania, Bosnia Herzegovina, 

Croatia, former Yugoslavian Republic of 

Macedonia, and Serbia. 

• South West Mediterranean 

– Algeria, Egypt, Libya, Morocco, and Tunisia. 

• South East Mediterranean 

– Turkey, Israel, Jordan, Lebanon, Palestine, and 

Syria. 

F.II General overview of 

the electrical system in 

Mediterranean 

Energy profile 

The Mediterranean region accounts for about 9% of 

the world’s energy demand and will have an estimated 

total electricity generation of about 3289 TWh by 

2030. Today most energy is consumed by the countries 

in the North of the Mediterranean Sea (70% of 

the total). 

Generally, the South Mediterranean countries are facing 

rapid demographic growth combined with relatively 

low incomes, a rapid urbanisation rate, and important 

socioeconomic development needs. These characteristics 

translate into a rapidly growing demand for 

energy services and related infrastructure. By contrast, 

the North Mediterranean countries are generally 

more mature economies, characterised by much more 

stable energy demand projections. 

64 As discussed previously, the three main drivers are security of supply, the economical trade of electricity, and the large-scale integration 

of renewable energy. 


Grid situation 

Interconnection lines exist across the borders of all 

the Mediterranean countries exist, with the exception 

of Israel. Nevertheless, the power systems around the 

Mediterranean basin are still split into three or four 

separated asynchronous 65 zones [49]: 

• The Northern Mediterranean countries are synchronously 

interconnected within ENTSO-E/SCR, 

which, since 1997, is interconnected with Morocco, 

Algeria and Tunisia after the first Morocco-Spain 

submarine interconnection was commissioned. 

• Turkey officially requested a connection to 

ENTSO-E/SCR in 2000, but further improvements 

of the Turkish system are still required before it is 

in line with ENTSO-E/SCR standards. 

• The Mashreq-Libya pool combines eight countries: 

Libya, Egypt, Jordan, Lebanon, Syria, Saudi Arabia, 

Palestinian Territories, and Iraq. 

• Israel and Palestinian Territories, which is an island 

grid. 

The most important existing bottlenecks are located 

between Greece and Turkey, Turkey and Syria, and between 

Tunisia and Libya. Additionally, the Net Transfer 

Capacity (NTC) remains weak across many borders. 

65 Please note that only the Northern Mediterranean countries are synchronously interconnected. A true integrated market with all 

countries operating synchronously is not seen as realistic in the next 10-20 years. 


Additionally, the inter-Mediterranean electrical exchanges 

are quite weak, especially between the 

Maghreb countries, despite the strong interconnections 

and a history of cooperation. The only link that is 

fully functional is the Spain-Morocco one. 

F.III Mediterranean Offshore 

Grid to be driven by RES 

development 

The analysis for Northern Europe assessed an offshore 

grid driven by the development of renewable 

energy sources (RES) (i.e. offshore wind). To interpret 

the results in the Mediterranean context, the expectations 

for RES development are investigated in this 

paragraph. 

F.III.I Introduction 

Large scale exploitation of renewable energy sources 

in the Mediterranean will be mainly based on wind 

power, solar photovoltaics (PV), and concentrated 

solar thermal power (CSP) plants. These three renewable 

energy technologies appear to have the greatest 

growth potential. 

table 15.1: OveRview OF wind pOweR develOpment and scenaRiOs FOR 2020 and 2030 in mediteRRanean 

region 

new capacity in 

2010 (MW) 

Wind capacity in 

2010 (MW) 

Wind capacity 

(2020) 

Wind capacity 

(2030) 

North 4,143 37,195 101,480 139,684 

EU countries 4,100 37,125 99,400 135,534 

Non-EU countries 43 70 2,080 4,150 

South East 528 1,339 9,250 20,400 

Turkey 528 1,329 8,000 18,000 

Other South East 0 10 1,250 2,400 

South West 213 950 9,000 16,700 

Algeria-Egypt-Libya 120 550 6,500 12,700 

Other South West 93 400 2,500 4,000 

total 4,884 39,484 119,730 176,784 

147


Wind power has been the fastest growing RES, and 

its costs are competitive to conventional power plants 

in good sites. Although wind potential is lower in the 

Mediterranean region than it is in Northern Europe, 

most of the countries have perspectives for wind power 

development, particularly EU countries through their 

national action plans. 

F.III.II Current status of wind power 

and prospects 

The total wind capacity installed today (2010) in the 

Mediterranean is 39.5GW. In 2010 alone, almost 

4.9GW of additional capacity was installed. Most of 

this capacity is installed in the countries in North 

Mediterranean 66 . 

Based on an analytical assessment of the industry development, 

the political situation in each country and 

taking into account previous studies on wind power 

development [24][20], long term wind power scenarios 

per country have been developed. The results are 

presented in Table 15.1. The total wind capacity is 

expected to increase from 39.5GW in 2010 to more 

than 119 GW in 2020 and 177 GW in 2030. The 

largest part of the development is expected in North 

Mediterranean countries, followed by Turkey. In the 

south western countries, south eastern countries and 

Northern Non-EU Mediterranean countries the development 

will be comparably much smaller. 

Nearly all of this planned capacity is located onshore. 

Offshore wind is discussed in the next section. 

F.III.III Offshore wind energy 

development in the Mediterranean 

Sea 

Prospects for offshore wind development are rather 

low in Mediterranean. Deep waters are a significant 

obstructing factor. 

There are no specific offshore scenarios for the 

Mediterranean Sea in literature. The lists of potential 

projects for offshore wind farms show that the majority 

of these plants will be very close to the mainland, playing 

a secondary role for offshore grid interconnections. 

Several uncertainties and challenges exist regarding 

offshore wind power development in Mediterranean: 

• Water depth 

• Complex orography 

• Visual impact, environmental issues and public acceptance 

(e.g. tourism) 

• Rather low wind potential 

• Financing 

Despite these uncertainties, North Mediterranean 

countries have set targets for offshore wind development 

in the Mediterranean Sea by 2020. France 

has set a target for 6 GW offshore, of which probably 

up to one third of this located in the Mediterranean 

(~2,000 MW). Italy and Spain have set a target for 

1,000 MW and 1,500 MW, while Greece has (low) 

target for 200 MW. This offshore development mainly 

concerns conventional offshore wind farms. Floating 

concepts are not foreseen until 2020. Current cost 

estimates of floating concepts (€5,000-6,000/kW) 

combined with the rather moderate wind potential 

indicate that these systems will not be economically 

viable in the Mediterranean before 2030. 

Offshore wind power is thus not likely to be the driving 

force for an offshore grid in the Mediterranean, 

although in some cases wind farms can probably teedin 

to shore-to-shore interconnectors. Therefore, also 

solar thermal and other RES are investigated in this 

report. 

66 Spain, Italy, France, Portugal, Greece and Cyprus together represent more than 93% of the overall installed wind power. 


F.III.IV Solar thermal power plants 

and photovoltaics 

In the Mediterranean region, most is expected from 

solar photovoltaics (PV) and solar thermal power 

plants (CSP). 

PV could supply a large share of the electricity needs 

in Mediterranean, but face two main constraints, which 

are the cost and the variability. The cost of PV is 3-5 

times higher than the cost of wind power. PV will firstly 

be installed in small quantities and very distributed, 

mitigating the power transmission needs and thus the 

impact on any kind of offshore transmission grid. 

CSP plants need more area for the installation and 

require direct sunlight. However, the cost is lower 

than for PV and is expected to decrease further in 

the near future, potentially becoming competitive 

with wind and conventional sources. Furthermore, 

significant economies of scale are possible for large 

plants, and the impact for the transmission grid is 

thus higher than for PV. 

FiGuRe 15.1: deseRtec map - the mediteRRanean sOlaR plan (sOuRce: deseRtec) 


There are several discussions about the exploitation of 

the abundant solar resource in isolated areas in North 

Africa, and on its transmission to local consumption 

centres and to Europe via high-voltage direct current 

(HVDC).transmission lines to the consumption centres. 

The primary countries under consideration are 

Algeria, Egypt, Morocco, Tunisia and Libya. The capacity 

which can be hosted is enormous, but in short term 

only few projects are considered (10 GW by 2020). 

F.IV Perspectives for offshore 

grid infrastructure in the 

Mediterranean 

The DESERTEC concept was developed by a network 

of politicians, scientists and economists from around 

the Mediterranean. The idea is to exploit the abundant 

solar resource in North-African deserts and transmit 

the electricity through high-voltage direct current grid 

to consumption centres in Europe (Figure 15.1). 

149


FiGuRe 15.2: euROpean eneRGy inFRastRuctuRe pRiORities FOR electRicity, Gas and Oil 

The European Commission identifies the interconnections 

in South-Western Europe as one of eight priority 

projects in the field of energy [23] (Figure 15.2). The 

recommended key actions include: 

• the adequate development of the interconnections 

in the Northern Mediterranean region and the accommodation 

of the existing national networks to 

those new projects, 

• concerning connections with NON-EU countries, the 

development of Italy’s connections with countries 

of the Energy Community, the realisation of the 

Tunisia-Italy interconnection, the expansion of the 

Spain-Morocco interconnector, the reinforcement, 

where necessary, of South-South interconnections 

in North African neighbour countries and 

preparatory studies for additional North-South interconnections 

to be developed after 2020. 


FiGuRe 15.3: selected aReas FOR analysis On the mediteRRanean map (sOuRce [51]) 

In 2008, the Heads of states and governments of the 

European and Mediterranean countries have launched 

the Union for the Mediterranean, to improve the regional 

cooperation. In the energy field, the flagship 

project of the Union for the Mediterranean will be the 

Mediterranean Solar Plan (MSP). The MSP aims at two 

complementary targets: developing 20 GW of new renewable 

energy production capacities and achieving 

significant energy savings around the Mediterranean 

by 2020, thus addressing both supply and demand 

[49]. It will help to address the challenges of internal 

energy demand in the participating countries, 

achieve the objectives of the EU Energy and Climate 

Package, significantly contribute to the sustainable development 

of non-EU countries, promote investments 

and create jobs. There is a special interest for the 

promotion of electricity transmission infrastructure, 

with specific attention for the improvement of North- 

South interconnections in order to allow the export of 

green electricity from Mediterranean countries to EU 

countries. In follow-up of the Second Strategic Energy 

Review [22], several studies have been prepared, 

among which one on possible power corridors [51] 

(Figure 15.3). 

An offshore grid in the Mediterranean Sea will mainly 

be built from direct shore-to-shore interconnectors. In 

some cases, tee-in solutions could be envisaged as 

well (e.g. Malta). 


F.V Recommendations for 

policy, market and regulatory 

framework 

The experience gained from Northern Europe shows 

that the driving forces for the development of an offshore 

grid is the development of RES, the removal of 

barriers and the regulation of the market [30]. Although 

the Mediterranean has abundant renewable energy 

resources, at present it is far from exploiting its full 

potential because of institutional, technical, political 

and market barriers. Moreover, not only the large scale 

development of RES but also further drivers such as 

the security of supply and economic issues will have 

to be considered when evaluating interconnections. 

F.V.I Legislative framework for 

RES - national targets 

Overcoming these barriers will require a strong political 

commitment as well as increased investments 

in the sector. A viable business climate in particular, 

based on stable and transparent investment frameworks 

with adequate pricing policies will be necessary 

for long-term investments to take place. 

The increase of the RES penetration is the critical factor 

which drives the evolution of offshore grid development 

151


in Northern Europe. Together with the increase of RES, 

the need for balancing is increased and the security 

of supply requires further strengthening of interconnections. 

It is recommended also for non-EU Mediterranean 

countries to develop national goals for RES. 

Development of RES, mainly wind power and solar 

thermal power in Mediterranean, requires parallel 

development of power interconnections for delivery 

to major load centres and maybe for transcontinental 

transfer. Implementation of long-term renewable 

energy policy programmes per country and national 

agreements for the development of RES and the reduction 

of greenhouse emissions are essential for the 

activation of the market. 

The regulatory framework for RES in the Mediterranean 

presents a quite diversified picture. While the EU 

countries in the North Mediterranean have been setting 

policies supporting renewables for a long time, 

the South Mediterranean countries have a less structured 

regime. In addition, subsidies to conventional 

energies in these countries represent a relevant barrier 

that prevents renewables from exploiting their 

whole potential. 

Additionally, RES development goals and their impact 

on an offshore grid vary considerably between countries. 

RES development goals have to be strongly 

integrated in the national and particularly the regional 

policy and stakeholder processes. This is to increase 

the social acceptance for grid enforcement or new 

RES capacity construction. 

In the regulatory field, Mediterranean has a lot to 

gain from the experience in North Europe. However, 

currently it is more important to deal with the lack of 

regulatory framework in several countries (i.e. Jordan, 

Israel, Lebanon, and Syria). Although such countries do 

not affect wind development, they have a strategic position 

and affect the development of interconnections. 

Economically, interconnections in Mediterranean could 

be incentivised by arbitrage possibilities between 

national power markets and can therefore improve 

market integration and power trading. 

Therefore, the Mediterranean countries should work 

together towards international harmonisation and 

regular consolidation of national policies concerning 

RES. In parallel, the standardisation of grid codes is 

also important, since four unsynchronised pools exist 

and each pool is characterised by its own codes and 

standards. 

F.V.II Market integration 

Market integration of a large geographical area, such 

as the Mediterranean, is very important to reinforce 

system reliability, improve security of supply, reduce 

operational reserves in the whole system and enhance 

the diversity of the available sources. 

Power interconnections and regional trading is 

considered as a mechanism for improving the 

economic efficiency of power systems. The value of 

the power interconnection is derived from the ability 

to achieve economies of scale, as individual smaller 

power systems can be operated and expanded as part 

of a larger regional system. 

Successful market integration requires a common 

framework for transactions to take place, harmonised 

arrangements for system operations, a system 

of tariffs for use of transmission infrastructure, 

and agreed principles and procedures for dispute 

resolution. 

To meet the challenge of market integration in 

Mediterranean, ways to finance extensions and 

harmonise the existing separated pools are 

required. For this purpose, economic and political 

improvements are essential, particularly in the weak 

countries of the region. 

F.V.III Political issues 

For the synchronised operation of the existing 

interconnections and the reinforcement with 

new onshore and offshore interconnections in 

Mediterranean, major technical and non-technical 

issues and concerns should be addressed. Political 

will and regional cooperation will become increasingly 

important as different parties, bodies and stakeholders 

work through these issues. 

Political stability is another important obstacle, which 

represents one of the major causes of insecurity 

regarding the upgrading of grid infrastructure. Civil 

wars, social unrest and political instability make it very 

difficult t to attract foreign funds and investors. 



OffshoreGrid project 

OffshoreGrid is a techno-economic study within the Intelligent Energy Europe programme. 

It developed a scientifically based view on an offshore grid in Northern Europe along with a 

suited regulatory framework considering technical, economic, policy and regulatory aspects. 

The project is targeted at European policy makers, industry, transmission system operators 

and regulators. The geographical scope was, first, the regions around the Baltic and North 

Sea, the English Channel and the Irish Sea. In a second phase, the results were applied 

to the Mediterranean region in qualitative terms. 

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